Pepco 10Q 2005 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 endedJune 30, 2005
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
Continued
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Securities registered pursuant to Section 12(b) of the Act:
Registrant		Title of Each Class			Name of Each Exchange on Which Registered
Pepco Holdings		Common Stock, $.01 par value			New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Pepco		Serial Preferred Stock, $50 par value
Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes X . No .
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
	Pepco Holdings			Yes X No
	Pepco			Yes No X
	DPL			Yes No X
	ACE			Yes No X
DPL and ACEmeet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with reduced disclosure format specified in General Instruction H(2) of Form 10-Q.
Registrant			Number of Shares of Common Stock of the Registrant Outstanding at June 30, 2005
Pepco Holdings			189,156,757 ($.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.

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TABLE OF CONTENTS
			Page
	Glossary of Terms		i
PART I	FINANCIAL INFORMATION		1
Item 1.	-	Financial Statements	1
Item 2.	-	Management's Discussion and Analysis of Financial Condition and Results of Operations	101
Item 3.	-	Quantitative and Qualitative Disclosures About Market Risk	183
Item 4.	-	Controls and Procedures	186
PART II	OTHER INFORMATION		188
Item 1.	-	Legal Proceedings	188
Item 2.	-	Unregistered Sales of Equity Securities and Use of Proceeds	188
Item 3.	-	Defaults Upon Senior Securities	189
Item 4.	-	Submission of Matters to a Vote of Security Holders	189
Item 5.	-	Other Information	191
Item 6.	-	Exhibits	191
Signatures			209
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TABLE OF CONTENTS - EXHIBITS
Exh. No.	Registrant(s)	Description of Exhibit	Page
12.1	PHI	Statements Re: Computation of Ratios	193
12.2	Pepco	Statements Re: Computation of Ratios	194
12.3	DPL	Statements Re: Computation of Ratios	195
12.4	ACE	Statements Re: Computation of Ratios	196
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	197
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	198
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	199
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	200
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	201
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	202
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	203
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	204
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	205
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	206
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	207
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	208
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	GLOSSARY OF TERMS
Term	Definition
ABO	Accumulated benefit obligation
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
ADITC	Accumulated deferred investment tax credits
ALJ	Administrative Law Judge
AOCI	Accumulated Other Comprehensive Income
AOCL	Accumulated Other Comprehensive Loss
APB	Accounting Principles Board Opinion
APB No. 25	Accounting Principles Board Opinion No. 25, entitled "Accounting for Stock Issued to Employees"
Asset Purchase and Sale Agreement	Asset Purchase and Sale Agreement, dated as of June 7, 2000 and subsequently amended, between Pepco and Mirant relating to the sale of Pepco's generation assets
Bankruptcy Court	Bankruptcy Court for the Northern District of Texas
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)
Competitive Energy Business	Consists of the business operations of Conectiv Energy and Pepco Energy Services
Conectiv	A wholly owned subsidiary of PHI which is a PUHCA holding company and the parent of DPL and ACE
Conectiv Energy	Conectiv Energy Holding Company and its subsidiaries
Court of Appeals	U.S. Court of Appeals for the Fifth Circuit
Creditor's Committee	The Official Committee of Unsecured Creditors of Mirant Corporation
D.C.	District of Columbia
DCPSC	District of Columbia Public Service Commission
Debentures	Junior Subordinated Debentures
Default Service	The supply of electricity by DPL to retail customers in Virginia who have not elected to purchase electricity from a competitive supplier
Default Electricity Supply	The supply of electricity within PHI's service territories 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 Default Service, SOS, BGS, or POLR service
Default Supply Revenue	The generic term for revenue received from Default Electricity Supply
District Court	U.S. District Court for the Northern District of Texas
DPL	Delmarva Power & Light Company
DPSC	Delaware Public Service Commission
EDECA	New Jersey Electric Discount and Energy Competition Act
EDIT	Excess deferred income tax
EPA	Environmental Protection Agency
ERISA	Employment Retirement Income Security Act of 1974
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN 45	FASB Interpretation No. 45, entitled "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others"
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Term	Definition
FIN 46R	FASB Interpretation No. 46 (revised December 2003), entitled "Consolidation of Variable Interest Entities"
FIN 47	FASB Interpretation No. 47, entitled "Accounting for Conditional Asset Retirement Obligations"
FirstEnergy	FirstEnergy Corp., formerly Ohio Edison
FirstEnergy PPA	PPAs between Pepco and FirstEnergy Corp. and Allegheny Energy, Inc.
Full Requirements Load Service	Delivery of actual load requirements to utilities based on actual customer consumption
GAAP	Generally Accepted Accounting Principles in the United States of America
GCR	Gas Cost Rate
GPC	Generation procurement credit
IRS	Internal Revenue Service
Internal Control over Financial Reporting	A process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Kwh	Kilowatt Hour
LTIP	Long-Term Incentive Plan
Mirant	Mirant Corporation (formerly Southern Energy, Inc.) and certain of its subsidiaries
Mirant Pre-Petition Obligations	Unpaid obligations of Mirant to Pepco existing at the time of filing of Mirant's bankruptcy petition consisting primarily of payments due Pepco in respect of the PPA-Related Obligations
MPSC	Maryland Public Service Commission
MTC	Market transition charge
NJBPU	New Jersey Board of Public Utilities
NJDEP	New Jersey Department of Environmental Protection
NOPR	IRS's Notice of proposed rulemaking
NUG	Non-utility generator
OCI	Other Comprehensive Income
OPC	Office of the People's Counsel
Other energy commodity activities	The competitive energy segments' commodity risk management and other energy market activities
Panda	Panda-Brandywine, L.P.
Panda PPA	PPA between Pepco and Panda
PCI	Potomac Capital Investment Corporation and its subsidiaries
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Term	Definition
Pepco	Potomac Electric Power Company
Pepco Energy Services	Pepco Energy Services, Inc. and its subsidiaries
Pepco Holdings or PHI	Pepco Holdings, Inc.
Pepco TPA Claim	Pepco's $105 million allowed, pre-petition general unsecured claim against Mirant
PJM	PJM Interconnection, LLC
PJM OATT	Open Access Transmission Tariff of PJM
POLR	Provider of Last Resort service (the supply of electricity by DPL before May 1, 2006 to retail customers in Delaware who have not elected to purchase electricity from a competitive supplier)
Power Delivery	PHI's Power Delivery Businesses
PPA	Power Purchase Agreement
PPA-Related Obligations	Mirant's obligations to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the FirstEnergy PPA and the Panda PPA
PRP	Potentially responsible party re EPA site cleanup
PUHCA	Public Utility Holding Company Act of 1935
RARC	Regulatory Asset Recovery Charge
Regulated electric revenues	Revenues for delivery (transmission and distribution) service and electricity supply service
SAB 107	SEC Staff Accounting Bulletin regarding SFAS No. 123 and 123R
SEC	Securities and Exchange Commission
Settlement Agreement	Amended Settlement Agreement and Release, dated as of October 24, 2003 between Pepco and Mirant
SFAS	Statement of Financial Accounting Standards
SFAS No. 13	Statement of Financial Accounting Standards No. 13, entitled "Accounting for Leases"
SFAS No. 123	Statement of Financial Accounting Standards No. 123, entitled "Accounting for Stock-Based Compensation"
SFAS No. 123R	Statement of Financial Accounting Standards No. 123R (Revised 2004) entitled "Share-Based Payment"
SFAS No. 131	Statement of Financial Accounting Standards No. 131, entitled "Disclosures About Segments of an Enterprise and Related Information"
SFAS No. 133	Statement of Financial Accounting Standards No. 133, entitled "Accounting for Derivative Instruments and Hedging Activities"
SFAS No. 143	Statement of Financial Accounting Standards No. 143, entitled "Accounting for Asset Retirement Obligations"
SFAS No. 148	Statement of Financial Accounting Standards No. 148, entitled "Accounting For Stock-Based Compensation - Transition and Disclosure"
SFAS No. 150	Statement of Financial Accounting Standards No. 150, entitled "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity"
SFAS No. 154	Statement of Financial Accounting Standards No. 154, entitled "Accounting Changes and Error Corrections"
SMECO	Southern Maryland Electric Cooperative, Inc.
SMECO Agreement	Capacity purchase agreement between Pepco and SMECO
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Term	Definition
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 on and after May 1, 2006, to retail customers who have not elected to purchase electricity from a competitive supplier)
Starpower	Starpower Communications, LLC
Stranded costs	Costs incurred by a utility in connection with providing service which would otherwise be unrecoverable in a competitive or restructured market. Such costs may include costs for generation assets, purchased power costs, and regulatory assets and liabilities, such as accumulated deferred income taxes.
TBC	Transition bond charge
T&D	Transmission and distribution
TPAs	Transition Power Agreements for Maryland and the District of Columbia between Pepco and Mirant
Transition Bonds	Transition bonds issued by ACE Funding
Treasury lock	A hedging transaction that allows a company to "lock-in" a specific interest rate corresponding to the rate of a designated Treasury bond for a determined period of time
VaR	Value at Risk
VSCC	Virginia State Corporation Commission
VRDB	Variable Rate Demand Bonds
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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
Unaudited Consolidated Statements of Earnings	3	45	67	83
Unaudited Consolidated Statements of Comprehensive Earnings	4	N/A	N/A	N/A
Unaudited Consolidated Balance Sheets	5	46	68	84
Unaudited Consolidated Statements of Cash Flows	7	48	70	86
Notes to Unaudited Consolidated Financial Statements	8	49	71	87

* The unaudited financial statements for Pepco and DPL are not consolidated.
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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EARNINGS (Unaudited)
	Three Months Ended June 30,						Six Months Ended June 30,
		2005			2004			2005			2004
		(Millions, except earnings per share)

Operating Revenues
Power Delivery	$	974.2		$	1,073.5		$	2,078.9		$	2,112.7
Competitive Energy		717.9			594.4			1,396.8			1,296.5
Other		20.0			23.6			41.2			46.4
Total Operating Revenues		1,712.1			1,691.5			3,516.9			3,455.6

Operating Expenses
Fuel and purchased energy		1,007.6			956.0			2,095.5			2,023.0
Other services cost of sales		182.5			167.3			353.1			328.2
Other operation and maintenance		187.3			184.8			379.3			382.8
Depreciation and amortization		101.8			109.4			207.5			222.2
Other taxes		76.2			64.2			158.1			136.2
Deferred electric service costs		(18.2	)		(6.0	)		.8			9.0
Gain on sale of assets		(3.9	)		(14.7	)		(4.3	)		(26.8	)
Total Operating Expenses		1,533.3			1,461.0			3,190.0			3,074.6

Operating Income		178.8			230.5			326.9			381.0

Other Income (Expenses)
Interest and dividend income		1.7			5.6			3.7			6.8
Interest expense		(84.7	)		(92.1	)		(167.5	)		(184.7	)
(Loss) income from equity investments		(1.9	)		13.2			(3.0	)		12.8
Impairment loss on equity investments		-			(11.2	)		-			(11.2	)
Other income		13.7			5.1			29.4			10.4
Other expenses		(2.7	)		(1.2	)		(3.4	)		(1.9	)
Total Other Expenses, Net		(73.9	)		(80.6	)		(140.8	)		(167.8	)

Preferred Stock Dividend Requirements of Subsidiaries		.7			.8			1.3			1.5

Income Before Income Tax Expense		104.2			149.1			184.8			211.7

Income Tax Expense		40.2			58.7			74.3			70.1

Income Before Extraordinary Item		64.0			90.4			110.5			141.6

Extraordinary Item (net of tax of $6.2 million)		-			-			9.0			-

Net Income		64.0			90.4			119.5			141.6

Retained Earnings at Beginning of Period		872.1			789.3			863.7			781.0

Dividends on Common Stock		(47.2	)		(43.0	)		(94.3	)		(85.9	)

Retained Earnings at End of Period	$	888.9		$	836.7		$	888.9		$	836.7

Basic and Diluted Share Information
Weighted average shares outstanding		188.8			172.2			188.6			172.0
Earnings per share of common stock:
Before extraordinary item	$	.34		$	.53		$	.58		$	.82
Extraordinary item		-			-			.05			-
Total	$	.34		$	.53		$	.63		$	.82

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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS (Unaudited)
	Three Months Ended June 30,						Six Months Ended June 30,
		2005			2004			2005		2004
		(Millions of Dollars)

Net income	$	64.0		$	90.4		$	119.5	$	141.6

Other comprehensive (losses)/earnings, net of taxes

Unrealized (losses)/gains on commodity derivatives designated as cash flow hedges:
Unrealized holding (losses)/gains arising during period		(4.1	)		(28.2	)		30.6		(6.3	)
Less: reclassification adjustment for gains included in net earnings		9.1			.7			13.1		2.2
Net unrealized (losses)/gains on commodity derivatives		(13.2	)		(28.9	)		17.5		(8.5	)

Realized gain on Treasury lock		3.0			3.0			5.9		5.9

Unrealized gains/(losses) on interest rate swap agreements designated as cash flow hedges:
Unrealized holding gains/(losses) arising during period		-			4.7			1.1		(4.3	)
Less: reclassification adjustment for (losses)/gains included in net earnings		(.1	)		(2.3	)		.8		(2.7	)
Net unrealized gains/(losses) on interest rate swaps		.1			7.0			.3		(1.6	)

Unrealized losses on marketable securities:
Unrealized holding losses arising during period		-			(3.9	)		-		(3.6	)
Less: reclassification adjustment for gains included in net earnings		-			.8			-		.8
Net unrealized losses on marketable securities		-			(4.7	)		-		(4.4	)

Other comprehensive (losses)/earnings, before taxes		(10.1	)		(23.6	)		23.7		(8.6	)

Income tax (benefit)/expense		(4.5	)		(9.5	)		9.1		(2.9	)

Other comprehensive (losses)/earnings, net of taxes		(5.6	)		(14.1	)		14.6		(5.7	)

Comprehensive earnings	$	58.4		$	76.3		$	134.1	$	135.9


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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
		June 30,			December 31,
ASSETS			2005			2004
	(Millions of Dollars)
CURRENT ASSETS
Cash and cash equivalents		$	177.1		$	29.6
Restricted cash			32.6			42.0
Accounts receivable, less allowance for uncollectible accounts of $45.6 million and $43.7 million, respectively			1,168.2			1,126.9
Fuel, materials and supplies - at average cost			277.0			268.4
Unrealized gains - derivative contracts			76.7			90.3
Prepaid expenses and other			142.0			119.6
Total Current Assets			1,873.6			1,676.8

INVESTMENTS AND OTHER ASSETS
Goodwill			1,431.3			1,430.5
Regulatory assets			1,294.6			1,335.4
Investment in finance leases held in trust			1,257.8			1,218.7
Prepaid pension expense			157.3			165.7
Other			494.3			466.1
Total Investments and Other Assets			4,635.3			4,616.4

PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			11,198.1			11,045.2
Accumulated depreciation			(3,949.3	)		(3,957.2	)
Net Property, Plant and Equipment			7,248.8			7,088.0

TOTAL ASSETS		$	13,757.7		$	13,381.2

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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
	June 30,				December 31,
LIABILITIES AND SHAREHOLDERS' EQUITY			2005			2004
		(Millions of dollars, except shares)

CURRENT LIABILITIES
Short-term debt	$		991.1		$	836.0
Accounts payable and accrued liabilities			712.5			663.5
Capital lease obligations due within one year			5.1			4.9
Taxes accrued			82.9			59.8
Interest accrued			89.6			90.1
Other			266.7			320.3
Total Current Liabilities			2,147.9			1,974.6

DEFERRED CREDITS
Regulatory liabilities			505.4			391.9
Income taxes			2,033.0			1,981.8
Investment tax credits			53.1			55.7
Other post-retirement benefit obligation			285.0			279.5
Other			229.1			203.7
Total Deferred Credits			3,105.6			2,912.6

LONG-TERM LIABILITIES
Long-term debt			4,322.2			4,362.1
Transition Bonds issued by ACE Funding			509.5			523.3
Long-term project funding			73.3			65.3
Capital lease obligations			119.4			122.1
Total Long-Term Liabilities			5,024.4			5,072.8

COMMITMENTS AND CONTINGENCIES (NOTE 4)

PREFERRED STOCK OF SUBSIDIARIES
Serial preferred stock			27.0			27.0
Redeemable serial preferred stock			27.9			27.9
Total Preferred Stock of Subsidiaries			54.9			54.9

SHAREHOLDERS' EQUITY
Common stock, $.01 par value, authorized 400,000,000 shares, 189,156,757 shares and 188,327,510 shares outstanding, respectively			1.9			1.9
Premium on stock and other capital contributions			2,585.0			2,566.2
Capital stock expense			(13.5	)		(13.5	)
Accumulated other comprehensive loss			(37.4	)		(52.0	)
Retained earnings			888.9			863.7
Total Shareholders' Equity			3,424.9			3,366.3

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$		13,757.7		$	13,381.2

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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
	Six Months Ended June 30,
		2005			2004
	(Millions of Dollars)
OPERATING ACTIVITIES
Net income	$	119.5		$	141.6
Adjustments to reconcile net income to net cash from operating activities:
Extraordinary item		(15.2	)		-
Depreciation and amortization		207.5			222.2
Gain on sale of assets		(4.3	)		(26.8	)
Gain on sale of other investment		(8.0	)		-
Impairment loss		-			11.2
Regulatory assets, net		(.4	)		(11.6	)
Rents received from leveraged leases under income earned		(39.2	)		(39.6	)
Deferred income tax expense		27.5			43.9
Changes in:
Accounts receivable		(9.2	)		(59.9	)
Accounts payable and accrued liabilities		24.1			(23.0	)
Interest and taxes accrued		36.3			(38.4	)
Other changes in working capital		(46.1	)		2.6
Net other operating activities		13.4			23.4
Net Cash From Operating Activities		305.9			245.6

INVESTING ACTIVITIES
Net investment in property, plant and equipment		(218.2	)		(233.2	)
Proceeds from sale of assets		4.6			39.8
Proceeds from the sale of other investments		23.8			15.1
Purchase of marketable securities		-			(19.2	)
Proceeds from sales of marketable securities		-			38.6
Net other investing activities		10.4			(30.4	)
Net Cash Used By Investing Activities		(179.4	)		(189.3	)

FINANCING ACTIVITIES
Dividends paid on common stock		(94.3	)		(85.9	)
Dividends paid on preferred stock		(1.3	)		(1.5	)
Common stock issued for the Dividend Reinvestment Plan		14.0			15.0
Redemption of debentures issued to financing trust		-			(95.0	)
Issuances of long-term debt		533.7			395.0
Reacquisition of long-term debt		(428.3	)		(459.2	)
Issuances of short-term debt, net		5.9			143.0
Cost of issuances and financings		(6.0	)		(10.4	)
Net other financing activities		(2.7	)		(2.4	)
Net Cash From (Used By) Financing Activities		21.0			(101.4	)

Net Increase (Decrease) in Cash and Cash Equivalents		147.5			(45.1	)
Cash and Cash Equivalents at Beginning of Period		29.6			90.6

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	177.1		$	45.5

NON CASH ACTIVITIES
Excess depreciation reserve transferred to regulatory liabilities	$	131.0		$	-
The accompanying Notes are an integral part of these unaudited Consolidated Financial Statements.

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

PEPCO HOLDINGS, INC.

(1) ORGANIZATION

Pepco Holdings, Inc. (Pepco Holdings or PHI) is a diversified energy company that, through its operating subsidiaries, is engaged in two principal business operations:

·	electricity and natural gas delivery (Power Delivery), and
·	competitive energy generation, marketing and supply (Competitive Energy).

PHI is a public utility holding company registered under the Public Utility Holding Company Act of 1935 (PUHCA) and is subject to the regulatory oversight of the Securities and Exchange Commission (SEC) under PUHCA. As a registered public utility holding company, PHI requires SEC approval to, among other things, issue securities, acquire or dispose of utility assets or securities of utility companies, and acquire other businesses. In addition, under PUHCA, transactions among PHI and its subsidiaries generally must be performed at cost and subsidiaries are prohibited from paying dividends out of capital or unearned surplus without SEC approval.

PHI was incorporated in Delaware on February 9, 2001, for the purpose of effecting the acquisition of Conectiv by Potomac Electric Power Company (Pepco). The acquisition was completed on August 1, 2002, at which time Pepco and Conectiv became wholly owned subsidiaries of PHI. Conectiv was formed in 1998 to be the holding company for Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE) in connection with a merger between DPL and ACE. As a result, DPL and ACE are wholly owned subsidiaries of Conectiv. Conectiv also is a registered public utility holding company under PUHCA.

PHI Service Company, a subsidiary service company of PHI, provides a variety of support services, including legal, accounting, tax, purchasing and information technology services to Pepco Holdings and its operating subsidiaries. These services are provided pursuant to a service agreement among PHI, PHI Service Company, and the participating operating subsidiaries that has been filed with, and approved by, the SEC under PUHCA. The expenses of the service company are charged to PHI and the participating operating subsidiaries in accordance with costing 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, which consists of the transmission and distribution of electricity and the distribution of natural gas. PHI's Power Delivery business is conducted by its three regulated utility subsidiaries: Pepco, DPL and ACE, each of which 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 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 service varies by jurisdiction as follows:

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	Delaware	Provider of Last Resort service (POLR) -- before May 1, 2006 Standard Offer Service (SOS) -- on and after May 1, 2006
	District of Columbia	Standard Offer Service
	Maryland	Standard Offer Service
	New Jersey	Basic Generation Service (BGS)
	Virginia	Default Service

PHI and its subsidiaries refer to this supply service in each of the jurisdictions generally as Default Electricity Supply.

The rates each company is permitted to charge for the transmission of electricity are regulated by the Federal Energy Regulatory Commission (FERC).

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.

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 subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv Energy) and Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services). Conectiv Energy and Pepco Energy Services are separate operating segments for financial reporting purposes.

Other Business Operations

Over the last several years, PHI has discontinued its investments in non-energy related businesses, including the sale of its aircraft portfolio and the sale of its 50% interest in Starpower Communications LLC (Starpower). These activities previously had been conducted through Potomac Capital Investment Corporation (PCI) and Pepco Communications, LLC, respectively. PCI's current activities are limited to the management of a portfolio of cross-border energy sale-leaseback transactions, with a book value at June 30, 2005 of approximately $1.2 billion. PCI does not plan on making new investments, and will focus on maintaining the earnings stream from its energy leveraged leases. These remaining operations constitute a single operating segment entitled "Other Non-Regulated" for financial reporting purposes.

(2) ACCOUNTING POLICY, PRONOUNCEMENTS, AND OTHER DISCLOSURES

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 SEC, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted.

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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, 2004. In the opinion of PHI's management, the consolidated financial statements contain all adjustments (which all are of a normal recurring nature) necessary to fairly state Pepco Holdings' financial condition as of June 30, 2005, its results of operations for the three and six months ended June 30, 2005, and its cash flows for the six months ended June 30, 2005 in accordance with GAAP. Interim results for the three and six months ended June 30, 2005 may not be indicative of PHI's results that will be realized for the full year ending December 31, 2005, since its Power Delivery subsidiaries' sales of electric energy are seasonal. Additionally, certain prior period balances have been reclassified in order to conform to current period presentation.

Adjustment to Pepco's First Quarter 2005 Unbilled Revenue

In the second quarter of 2005, Pepco recorded an adjustment to correct the unbilled revenue amounts that were reported in the first quarter of 2005. This adjustment reduced PHI's and Pepco's second quarter earnings in each case by $4.4 million (2 cents per share for PHI). The adjustment had no impact on earnings for the six months ended June 30, 2005.

FIN 45

As of June 30, 2005, Pepco Holdings did not have material obligations under guarantees or indemnifications issued or modified after December 31, 2002, which are required to be recognized as liabilities on its consolidated balance sheets; however, certain energy marketing obligations of Conectiv Energy were recorded as liabilities.

FIN 46R

Subsidiaries of Pepco Holdings have power purchase agreements (PPAs) with a number of entities including three ACE Non-Utility Generation contracts (ACE NUGs) and an agreement of Pepco (Panda PPA) with Panda-Brandywine, L.P. (Panda). Due to a variable element in the pricing structure of the ACE NUGs and the Panda PPA, the Pepco Holdings' subsidiaries potentially assume the variability in the operations of the plants of these entities and therefore have a variable interest in the counterparties to these PPAs. As required by FIN 46R, Pepco Holdings continued to conduct exhaustive efforts to obtain information from these four entities, but was unable to obtain sufficient information from these four entities to conduct the analysis required under FIN 46R to determine whether these four entities were variable interest entities or if Pepco Holdings' subsidiaries were the primary beneficiary. As a result, Pepco Holdings has applied the scope exemption from the application of FIN 46R for enterprises that have conducted exhaustive efforts to obtain the necessary information.

Net purchase activities with the counterparties to the ACE NUGs and the Panda PPA in the quarters ended June 30, 2005 and 2004 were approximately $94 million and $82 million, respectively, of which approximately $86 million and $75 million, respectively, related to power purchases under the ACE NUGs and the Panda PPA. Net purchase activities with the counterparties to the ACE NUGs and the Panda PPA in the six months ended June 30, 2005 and 2004 were approximately $193 million and $169 million, respectively, of which approximately $177 million and $154 million, respectively, related to power purchases under the ACE NUGs and the Panda PPA. Pepco Holdings' exposure to loss under the agreement with Panda entered into in 1991, pursuant to which Pepco is obligated to purchase from Panda 230 megawatts of

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capacity and energy annually through 2021, is discussed in Note (4), Commitments and Contingencies, under "Relationship with Mirant Corporation." Pepco Holdings does not have loss exposure under the ACE NUGs because cost recovery will be achieved from ACE's customers through regulated rates.

Components of Net Periodic Benefit Cost/(Income)

The following Pepco Holdings' information is for the three months ended June 30, 2005 and 2004.

		Pension Benefits						Other Post-Retirement Benefits
		2005			2004			2005			2004
	(In Millions)
Service cost	$	9.6		$	8.4		$	2.1		$	2.4
Interest cost		23.6			23.5			8.4			8.3
Expected return on plan assets		(32.1	)		(32.3	)		(2.9	)		(2.8	)
Amortization of prior service cost		.3			.3			(.9	)		-
Amortization of net loss		2.7			(1.3	)		3.4			3.1
Net periodic benefit cost/(income)	$	4.1		$	(1.4	)	$	10.1		$	11.0

The following Pepco Holdings' information is for the six months ended June 30, 2005 and 2004.

		Pension Benefits						Other Post-Retirement Benefits
		2005			2004			2005			2004
	(In Millions)
Service cost	$	19.0		$	18.0		$	4.2		$	4.8
Interest cost		47.9			47.3			16.8			16.7
Expected return on plan assets		(62.8	)		(62.1	)		(5.4	)		(5.7	)
Amortization of prior service cost		.6			.5			(1.9	)		-
Amortization of net loss		5.2			3.3			5.9			6.2
Net periodic benefit cost	$	9.9		$	7.0		$	19.6		$	22.0

Pension

The 2005 pension net periodic benefit cost/(income) for the three months ended June 30, of $4.1 million includes $2.5 million for Pepco, $2.0 million for ACE, and $(2.6) million for DPL. The 2005 pension net periodic benefit cost/(income) for the six months ended June 30, of $9.9 million includes $5.1 million for Pepco, $4.1 million for ACE, and $(3.9) million for DPL. The remaining pension net periodic benefit cost is for other PHI subsidiaries. The 2004 pension net periodic benefit cost/(income) for the three months ended June 30, of $(1.4) million includes $.2 million for Pepco, $1.5 million for ACE, and $(3.9) million for DPL. The 2004 pension net periodic benefit cost/(income) for the six months ended June 30, of $7.0 million includes $3.7

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million for Pepco, $3.5 million for ACE, and $(4.4) million for DPL. The remaining pension net periodic benefit cost is for other PHI subsidiaries.

The six months ended June 30, 2005 pension net periodic benefit cost reflects a reduction in the expected return on assets assumption from 8.75% to 8.50% effective January 1, 2005.

Pension Contributions

Pepco Holdings' current funding policy with regard to its defined benefit pension plan is to maintain a funding level in excess of 100% of its accumulated benefit obligation (ABO). In 2004 and 2003 PHI made discretionary tax-deductible cash contributions to the plan of $10 million and $50 million, respectively. PHI's pension plan currently meets the minimum funding requirements of the Employment Retirement Income Security Act of 1974 (ERISA) without any additional funding. PHI may elect, however, to make a discretionary tax-deductible contribution to maintain the pension plan's assets in excess of its ABO. As of June 30, 2005, no contributions have been made. The potential discretionary funding of the pension plan in 2005 will depend on many factors, including the actual investment return earned on plan assets over the remainder of the year.

Other Post-Retirement Benefits

The 2005 other post-retirement net periodic benefit cost for the three months ended June 30, of $10.1 million includes $6.0 million for Pepco, $2.0 million for ACE, and $.5 million for DPL. The 2005 other post-retirement net periodic benefit cost for the six months ended June 30, of $19.6 million includes $9.0 million for Pepco, $4.4 million for ACE, and $3.0 million for DPL. The remaining other post-retirement net periodic benefit cost is for other PHI subsidiaries. The 2004 other post-retirement net periodic benefit cost for the three months ended June 30, of $11.0 million includes $4.5 million for Pepco, $2.5 million for ACE, and $2.3 million for DPL. The 2004 other post-retirement net periodic benefit cost for the six months ended June 30, of $22.0 million includes $9.0 million for Pepco, $4.9 million for ACE, and $4.7 million for DPL. The remaining other post-retirement net periodic benefit cost is for other PHI subsidiaries.

The six months ended June 30, 2005 other post-retirement net periodic benefit cost reflects a reduction in the expected return on assets assumption from 8.75% to 8.50% effective January 1, 2005.

Stock-Based Compensation

The objective of Pepco Holdings' Long-Term Incentive Plan (the LTIP) is to increase shareholder value by providing a long-term incentive to reward officers, key employees, and directors of Pepco Holdings and its subsidiaries and to increase the ownership of Pepco Holdings' common stock by such individuals. Any officer or key employee of Pepco Holdings or its subsidiaries may be designated by PHI's Board of Directors as a participant in the LTIP. Under the LTIP, awards to officers and key employees may be in the form of restricted stock, options, performance units, stock appreciation rights, or dividend equivalents. No awards were granted during the six months ended June 30, 2005.

Pepco Holdings recognizes compensation costs for the LTIP based on the provisions of Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." In accordance with Financial Accounting Standards Board (FASB) Statement No. 123,

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"Accounting for Stock-Based Compensation" (SFAS No. 123), as amended by FASB Statement No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," the following table illustrates what the effect on net income and basic and diluted earnings per share would have been if Pepco Holdings had applied the fair value based method of expense recognition and measurement provisions of SFAS No. 123 to stock-based employee compensation.

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
		2005			2004			2005			2004
	(Millions, except Per Share Data)
Net Income, as reported	$	64.0		$	90.4		$	119.5		$	141.6
Add: Total stock-based employee compensation cost (net of related tax effect of $.6 million and $.4 million for the three months ended and $1 million and $.8 million for the six months ended June 30, 2005 and 2004, respectively) included in net income		.9			.7			1.5			1.4
Deduct: Total stock-based employee compensation expense determined under fair value based methods for all awards (net of related tax effect of $.6 million and $.5 million for the three months ended June 30, 2005 and 2004 and $1.1 million for each of the six months ended June 30, 2005 and 2004)		(.9	)		(.9	)		(1.6	)		(2.0	)
Pro forma net income	$	64.0		$	90.2		$	119.4		$	141.0

Basic and Diluted average common shares outstanding		188.8			172.2			188.6			172.0
Basic and Diluted earnings per share, as reported	$	.34		$	.53		$	.63		$	.82
Pro forma Basic and Diluted earnings per share	$	.34		$	.52		$	.63		$	.82

Debt

On May 5, 2005, Pepco Holdings, Pepco, DPL and ACE entered into a five-year credit agreement with an aggregate borrowing limit of $1.2 billion. This agreement replaces a $650 million five-year credit agreement that was entered into in July 2004 and a $550 million three-year credit agreement entered into in July 2003. Pepco Holdings' credit limit under this agreement is $700 million. The credit limit of each of Pepco, DPL and ACE is the lower of $300 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 under the agreement may not exceed $500 million. Under the terms of the credit agreement, the companies are entitled to request increases in the principal amount of available credit up to an aggregate increase of $300 million, with any such increase proportionately increasing the credit limit of each of the respective borro wers and the $300 million sublimits for each of Pepco, DPL and ACE. The interest rate payable by the respective

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companies on utilized funds will be based on a pricing schedule determined by the credit rating of the borrower. Any indebtedness incurred under the Credit Agreement would be unsecured.

The credit agreement 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 made by the borrower at the time the credit agreement was entered into also must be true at the time the facility is utilized, and the borrower must be in compliance with specified covenants, including the financial covenant described below. However, a material adverse change in the borrower's business, property, or financial condition subsequent to the entry into the credit agreement is not a condition to the availability of credit under the facility. Among the covenants contained in the credit agreement are (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 6 5% or less, computed in accordance with the terms of the credit agreement, (ii) a restriction on sales or other dispositions of assets, other than sales and dispositions permitted by the credit agreement and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than liens permitted by the credit agreement. The failure to satisfy any of the covenants or the occurrence of specified events that constitute events of default that could result in the acceleration of repayment obligations of the borrower. The events of default include (i) the failure of any borrowing company or any of its significant subsidiaries to pay when due, or the acceleration of, certain indebtedness under other borrowing arrangements, (ii) certain bankruptcy events, judgments or decrees against any borrowing company or its significant subsidiaries, and (iii) a change in control (as defined in the credit agreement) of Pepco Holdings or the f ailure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE. The agreement does not include any ratings triggers.

In June 2005, Pepco issued $175 million of 5.40% senior secured notes due 2035. The net proceeds will be used to redeem, on or after September 15, 2005, $75 million of 7.375% first mortgage bonds due September 15, 2025 and to pay at maturity $100 million of 6.50% first mortgage bonds due September 15, 2005. The proceeds from this issuance were included in cash and cash equivalents at June 30, 2005.

In June 2005, DPL issued $100 million of 5.0% unsecured notes due 2015. The net proceeds were used to redeem $100 million of DPL's 7.71% first mortgage bonds due 2025.

In June 2005, DPL made a sinking fund payment of $2.7 million on its 6.95% first mortgage bonds due 2008.

In June 2005, Conectiv paid at maturity $250 million of its 5.30% notes, $30 million of its 6.73% notes and called for early redemption the remaining $20 million of its 6.73% notes due 2006. As of June 30, 2005, Conectiv has no public debt outstanding.

In June 2005, Pepco Holdings issued $250 million of floating rate unsecured notes due 2010. The net proceeds were used to repay commercial paper issued to fund the redemptions of Conectiv debt.

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Effective Tax Rate

PHI's effective tax rate for the three months ended June 30, 2005 was 38% as compared to the federal statutory rate of 35%. The major reasons for the difference between the effective tax rate and the statutory tax rate were state income taxes (net of federal benefit), changes in estimates related to tax liabilities for prior tax years subject to audit and the flow-through of certain book tax depreciation differences, partially offset by the flow-through of deferred investment tax credits and tax benefits related to certain leveraged leases.

PHI's effective tax rate for the three months ended June 30, 2004 was 39% as compared to the federal statutory rate of 35%. The major reasons for the difference between the effective tax rate and the statutory tax rate were state income taxes (net of federal benefit) and the flow-through of certain book tax depreciation differences, partially offset by the flow-through of Deferred Investment Tax Credits and tax benefits related to certain leveraged leases.

PHI's effective tax rate for the six months ended June 30, 2005 was 40% as compared to the federal statutory rate of 35%. The major reasons for the difference between the effective tax rate and the statutory tax rate were state income taxes (net of federal benefit), changes in estimates related to tax liabilities for prior tax years subject to audit and the flow-through of certain book tax depreciation differences, partially offset by the flow-through of deferred investment tax credits and tax benefits related to certain leveraged leases.

PHI's effective tax rate for the six months ended June 30, 2004 was 33% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit, including the benefit associated with the retroactive adjustment for the issuance of final consolidated tax return regulations by a local taxing authority, which is the primary reason for the lower effective rate as compared to 2005), the flow-through of deferred investment tax credits and tax benefits related to certain leveraged leases, partially offset by the flow-through of certain book tax depreciation differences.

Extraordinary Item

On April 19, 2005, a settlement of ACE's electric distribution rate case was reached among ACE, the staff of the New Jersey Board of Public Utilities (NJBPU), the New Jersey Ratepayer Advocate, and active intervenor parties. As a result of this settlement, ACE reversed $15.2 million ($9.0 million, after-tax) in accruals related to certain deferred costs that are now deemed recoverable. The after-tax credit to income of $9.0 million is classified as an extraordinary item (gain) since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.

New Accounting Standards

SFAS No. 154

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correction of an error by restating previously issued financial statements is also addressed by SFAS No. 154. This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Early adoption is permitted.

SAB 107 and SFAS 123R

In March 2005, the SEC issued Staff Accounting Bulletin No. 107 (SAB 107) which provides implementation guidance on the interaction between FASB Statement No. 123 (revised 2004),Share-Based Payment (SFAS 123R) and certain SEC rules and regulations as well as guidance on the valuation of share-based payment arrangements for public companies.

In April 2005, the SEC adopted a rule delaying the effective date of SFAS 123R for public companies. Under the rule, most registrants must comply with SFAS 123R beginning with the first interim or annual reporting period of their first fiscal year beginning after June 15, 2005 (i.e., the year ended December 31, 2006 for Pepco Holdings). Pepco Holdings is in the process of completing its evaluation of the impact of SFAS 123R and does not anticipate that its implementation or SAB 107 will have a material effect on PHI's overall financial condition or results of operations.

FIN 47

In March 2005, the FASB published FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations"(FIN 47). FIN 47 clarifies that FASB Statement No. 143," Accounting for Asset Retirement Obligations" applies to conditional asset retirement obligations and requires that the fair value of a reasonably estimable conditional asset retirement obligation be recognized as part of the carrying amounts of the asset. FIN 47 is effective no later than the end of the first fiscal year ending after December 15, 2005 (i.e., December 31, 2005 for Pepco Holdings). Pepco Holdings is in the process of evaluating the anticipated impact that the implementation of FIN 47 will have on its overall financial condition or results of operations.

(3) SEGMENT INFORMATION

Based on the provisions of Statement of Financial Accounting Standards (SFAS) No. 131, "Disclosures about Segments of an Enterprise and Related Information," Pepco Holdings' management has identified its operating segments at June 30, 2005 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. Intercompany (intersegment) revenues and expenses are not eliminated in the segment columns for purposes of presenting segment financial results. These intercompany eliminations are shown on the "Corp. & Other" column which reconciles the cumulative segment results and the PHI consolidated results. Segment financial information for the three and six months ended June 30, 2005 and 2004, in millions of dollars, is as follows.

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		For the Three Months Ended June 30, 2005
					Competitive Energy Segments
			Power Delivery			Conectiv Energy			Pepco Energy Services		Other Non-Regulated		(a) Corp. & Other			PHI Cons
Operating Revenue		$	974.2		$	584.2	(b)	$	320.2	$	20.5	$	(187.0	)	$	1,712.1
Operating Expense			855.6	(b)		555.6			306.5		1.0		(185.4	)		1,533.3
Operating Income (Loss)			118.6			28.6			13.7		19.5		(1.6	)		178.8
Interest Income			1.2			7.6			.3		25.1		(32.5	)		1.7
Interest Expense			43.7			14.4			.8		34.4		(8.6	)		84.7
Income Tax Expense (Benefit)			34.6			8.3			5.0		1.4		(9.1	)		40.2
Net Income (Loss)		$	48.1		$	12.9		$	8.7	$	8.9	$	(14.6	)	$	64.0
Total Assets		$	8,818.7		$	1,939.3		$	504.3	$	1,356.3	$	1,139.1		$	13,757.7
Construction Expenditures		$	122.1		$	2.8		$	3.3	$	-	$	1.7		$	129.9

(a)	Includes inter-segment eliminations and 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 non-regulated Conectiv assets and liabilities as of August 1, 2002. The "total assets" line of this column includes Pepco Holdings' goodwill balance.
(b)	Power Delivery purchased electric energy, electric capacity and natural gas from Conectiv Energy in the amount of $128.9 million for the three months ended June 30, 2005.

		For the Three Months Ended June 30, 2004
					Competitive Energy Segments
			Power Delivery			Conectiv Energy			Pepco Energy Services		Other Non-Regulated			(a) Corp. & Other			PHI Cons
Operating Revenue		$	1,073.5		$	565.4	(b)	$	243.5	$	24.2		$	(215.1	)	$	1,691.5
Operating Expense			908.4	(b)		531.1			237.9		1.6			(218.0	)		1,461.0
Operating Income			165.1			34.3			5.6		22.6			2.9			230.5
Interest Income			1.6			1.1			.1		15.9			(13.1	)		5.6
Interest Expense			45.1			7.5			.6		21.8			17.1			92.1
Income Tax Expense (Benefit)			51.9			16.1			2.0		(1.3	)		(10.0	)		58.7
Net Income (Loss)		$	72.5		$	24.5		$	3.5	$	6.9		$	(17.0	)	$	90.4
Total Assets		$	8,448.3		$	1,979.1		$	534.1	$	1,353.4		$	1,115.7		$	13,430.6
Construction Expenditures		$	131.5		$	1.8		$	4.2	$	-		$	.6		$	138.1

(a)	Includes inter-segment eliminations and 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 non-regulated Conectiv assets and liabilities as of August 1, 2002. The "total assets" line of this column includes Pepco Holdings' goodwill balance.
(b)	Power Delivery purchased electric energy, electric capacity and natural gas from Conectiv Energy in the amount of $149.3 million for the three months ended June 30, 2004.

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		For the Six Months Ended June 30, 2005
					Competitive Energy Segments
			Power Delivery			Conectiv Energy			Pepco Energy Services		Other Non-Regulated		(a) Corp. & Other			PHI Cons
Operating Revenue		$	2,078.9		$	1,093.6	(b)	$	672.8	$	41.0	$	(369.4	)	$	3,516.9
Operating Expense			1,846.3	(b)		1,051.4			655.0		2.2		(364.9	)		3,190.0
Operating Income (Loss)			232.6			42.2			17.8		38.8		(4.5	)		326.9
Interest Income			2.5			14.7			.7		45.9		(60.1	)		3.7
Interest Expense			85.3			28.3			1.7		64.4		(12.2	)		167.5
Income Tax Expense (Benefit)			68.6			12.8			6.7		5.8		(19.6	)		74.3
Extraordinary Item (net of taxes of $6.2 million)			9.0	(c)		-			-		-		-			9.0
Net Income (Loss)		$	100.4		$	16.0		$	11.1	$	22.5	$	(30.5	)	$	119.5
Total Assets		$	8,818.7		$	1,939.3		$	504.3	$	1,356.3	$	1,139.1		$	13,757.7
Construction Expenditures		$	207.1		$	4.4		$	4.2	$	-	$	2.5		$	218.2

(a)	Includes inter-segment eliminations and 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 non-regulated Conectiv assets and liabilities as of August 1, 2002. The "total assets" line of this column includes Pepco Holdings' goodwill balance.
(b)	Power Delivery purchased electric energy, electric capacity and natural gas from Conectiv Energy in the amount of $248.3 million for the six months ended June 30, 2005.
(c)	Relates to ACE's electric distribution rate case settlement that was accounted for in the first quarter of 2005. This resulted in ACE's reversal of $9.0 million in after-tax accruals related to certain deferred costs that are now deemed recoverable. This amount is classified as extraordinary since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.

		For the Six Months Ended June 30, 2004
					Competitive Energy Segments
			Power Delivery			Conectiv Energy			Pepco Energy Services		Other Non-Regulated			(a) Corp. & Other			PHI Cons
Operating Revenue		$	2,112.7		$	1,153.2	(b)	$	554.2	$	45.3		$	(409.8	)	$	3,455.6
Operating Expense			1,839.1	(b)		1,103.4			545.8		(1.7	)		(412.0	)		3,074.6
Operating Income			273.6			49.8			8.4		47.0			2.2			381.0
Interest Income			4.1			2.2			.2		27.3			(27.0	)		6.8
Interest Expense			91.6			14.9			1.2		43.2			33.8			184.7
Income Tax Expense (Benefit) (c)			79.1			19.5			1.5		(7.1	)		(22.9	)		70.1
Net Income (Loss)		$	113.3		$	29.6		$	6.8	$	27.0		$	(35.1	)	$	141.6
Total Assets		$	8,448.3		$	1,979.1		$	534.1	$	1,353.4		$	1,115.7		$	13,430.6
Construction Expenditures		$	222.4		$	4.7		$	5.0	$	-		$	1.1		$	233.2

(a)	Includes inter-segment eliminations and 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 non-regulated Conectiv assets and liabilities as of August 1, 2002. The "total assets" line of this column includes Pepco Holdings' goodwill balance.
(b)	Power Delivery purchased electric energy, electric capacity and natural gas from Conectiv Energy in the amount of $297.3 million for the six months ended June 30, 2004.
(c)	In February 2004, a local jurisdiction issued final consolidated tax return regulations, which were retroactive to 2001. Under these regulations, Pepco Holdings (parent company) and other affiliated companies doing business in this location now have the necessary guidance to file a consolidated income tax return. This allows Pepco Holdings' subsidiaries with taxable losses to utilize those losses against tax liabilities of Pepco Holdings' companies with taxable income. During the first quarter of 2004, Pepco Holdings and its subsidiaries recorded the impact of the new regulations of $13.2 million for 2001 through 2003.

(4) COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Relationship with Mirant Corporation

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Corporation and most of its subsidiaries filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas (the Bankruptcy Court).

Depending on the outcome of the matters discussed below, the Mirant bankruptcy could have a material adverse effect on the results of operations of Pepco Holdings and Pepco. However, management believes that Pepco Holdings and Pepco currently have sufficient cash, cash flow and borrowing capacity under their credit facilities and in the capital markets to be able to satisfy any additional cash requirements that may arise due to the Mirant bankruptcy. Accordingly, management does not anticipate that the Mirant bankruptcy will impair the ability of Pepco Holdings or Pepco to fulfill their contractual obligations or to fund projected capital expenditures. On this basis, management currently does not believe that the Mirant bankruptcy will have a material adverse effect on the financial condition of either company.

Transition Power Agreements

As part of the Asset Purchase and Sale Agreement, Pepco and Mirant entered into Transition Power Agreements for Maryland and the District of Columbia, respectively (collectively, the TPAs). Under these agreements, Mirant was obligated to supply Pepco with all of the capacity and energy needed to fulfill its SOS obligations in Maryland through June 2004 and its SOS obligations in the District of Columbia through January 22, 2005.

To avoid the potential rejection of the TPAs, Pepco and Mirant entered into an Amended Settlement Agreement and Release dated as of October 24, 2003 (the Settlement Agreement) pursuant to which Mirant assumed both of the TPAs and the terms of the TPAs were modified. The Settlement Agreement also provided that Pepco has an allowed, pre-petition general unsecured claim against Mirant Corporation in the amount of $105 million (the Pepco TPA Claim).

Pepco has also asserted the Pepco TPA Claim against other Mirant entities, which Pepco believes are liable to Pepco under the terms of the Asset Purchase and Sale Agreement's Assignment and Assumption Agreement (the Assignment Agreement). Under the Assignment Agreement, Pepco believes that each of the Mirant entities assumed and agreed to discharge certain liabilities and obligations of Pepco as defined in the Asset Purchase and Sale Agreement. Mirant has filed objections to these claims. Under the original plan of reorganization filed by the Mirant entities with the Bankruptcy Court, certain Mirant entities other than Mirant Corporation would pay significantly higher percentages of the claims of their creditors than would Mirant Corporation. The amount that Pepco will be able to recover from the Mirant bankruptcy estate with respect to the Pepco TPA Claim will depend on the amount of assets available for distribution to creditors of the Mirant entities that are found to b e liable for the Pepco TPA Claim.

Power Purchase Agreements

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purchase price is substantially in excess of current market price. As a part of the Asset Purchase and Sale Agreement, Pepco entered into a "back-to-back" arrangement with Mirant. Under this arrangement, Mirant is obligated, among other things, to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the FirstEnergy PPA and the Panda PPA at a price equal to the price Pepco is obligated to pay under the FirstEnergy PPA and the Panda PPA (the PPA-Related Obligations).

Pepco Pre-Petition Claims

When Mirant filed its bankruptcy petition on July 14, 2003, Mirant had unpaid obligations to Pepco of approximately $29 million, consisting primarily of payments due to Pepco in respect of the PPA-Related Obligations (the Mirant Pre-Petition Obligations). The Mirant Pre-Petition Obligations constitute part of the indebtedness for which Mirant is seeking relief in its bankruptcy proceeding. Pepco has filed Proofs of Claim in the Mirant bankruptcy proceeding in the amount of approximately $26 million to recover this indebtedness; however, the amount of Pepco's recovery, if any, is uncertain. The $3 million difference between Mirant's unpaid obligation to Pepco and the $26 million Proofs of Claim primarily represents a TPA settlement adjustment that is included in the $105 million Proofs of Claim filed by Pepco against the Mirant debtors in respect of the Pepco TPA Claim. In view of the uncertainty as to recoverability, Pepco, in the third quarter of 2003, expensed $14.5 milli on to establish a reserve against the $29 million receivable from Mirant. In January 2004, Pepco paid approximately $2.5 million to Panda in settlement of certain billing disputes under the Panda PPA that related to periods after the sale of Pepco's generation assets to Mirant. Pepco believes that under the terms of the Asset Purchase and Sale Agreement, Mirant is obligated to reimburse Pepco for the settlement payment. Accordingly, in the first quarter of 2004, Pepco increased the amount of the receivable due from Mirant by approximately $2.5 million and amended its Proofs of Claim to include this amount. Pepco currently estimates that the $14.5 million expensed in the third quarter of 2003 represents the portion of the entire $31.5 million receivable unlikely to be recovered in bankruptcy, and no additional reserve has been established for the $2.5 million increase in the receivable. The amount expensed represents Pepco's estimate of the possible outcome in bankruptcy, although the amount ultimately re covered could be higher or lower.

Mirant's Attempt to Reject the PPA-Related Obligations

In August 2003, Mirant filed with the Bankruptcy Court a motion seeking authorization to reject its PPA-Related Obligations. Upon motions filed with the U.S. District Court for the Northern District of Texas (the District Court) by Pepco and FERC, in October 2003, the District Court withdrew jurisdiction over the rejection proceedings from the Bankruptcy Court. In December 2003, the District Court denied Mirant's motion to reject the PPA-Related Obligations on jurisdictional grounds. The District Court's decision was appealed by Mirant and The Official Committee of Unsecured Creditors of Mirant Corporation (the Creditors' Committee) to the U.S. Court of Appeals for the Fifth Circuit (the Court of Appeals). In August 2004, the Court of Appeals remanded the case to the District Court saying that the District Court had jurisdiction to rule on the merits of Mirant's rejection motion, suggesting that in doing so the court apply a "more rigorous standard" than the business judg ment rule usually applied by bankruptcy courts in ruling on rejection motions.

On December 9, 2004, the District Court issued an order again denying Mirant's motion to reject the PPA-Related Obligations. The District Court found that the PPA-Related Obligations

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are not severable from the Asset Purchase and Sale Agreement and that the Asset Purchase and Sale Agreement cannot be rejected in part, as Mirant was seeking to do. On December 16, 2004, the Creditors' Committee appealed the District Court's order to the Court of Appeals, and on December 20, 2004, Mirant also appealed the District Court's order. Mirant and the Creditors' Committee each filed its brief on April 4, 2005. Pepco's and FERC's briefs were filed in May 2005. Oral arguments have not yet been scheduled.

Until December 9, 2004, Mirant had been making regular periodic payments in respect of the PPA-Related Obligations. However, on that date, Mirant filed a notice with the Bankruptcy Court that it was suspending payments to Pepco in respect of the PPA-Related Obligations and subsequently failed to make certain full and partial payments due to Pepco. Proceedings ensued in the Bankruptcy Court and the District Court, ultimately resulting in Mirant being ordered to pay to Pepco all past-due unpaid amounts under the PPA-Related Obligations. On April 13, 2005, Pepco received a payment from Mirant in the amount of approximately $57.5 million, representing the full amount then due in respect of the PPA-Related Obligations.

On January 21, 2005, Mirant filed in the Bankruptcy Court a motion seeking to reject certain of its ongoing obligations under the Asset Purchase and Sale Agreement, including the PPA-Related Obligations (the Second Motion to Reject). On March 1, 2005, the District Court entered an order (which was amended on March 7, 2005) granting Pepco's motion to withdraw jurisdiction over the Asset Purchase and Sale Agreement rejection proceedings from the Bankruptcy Court. On March 28, 2005, Pepco, the Federal Energy Regulatory Commission (FERC), the Office of People's Counsel (OPC) of the District of Columbia, the Maryland Public Service Commission (MPSC) and the Maryland OPC filed oppositions to the Second Motion to Reject in the District Court. On July 15, 2005, Mirant filed a supplemental brief with the District Court in support of its Second Motion to Reject, addressing a June 17, 2005 FERC order (discussed below under "Mirant Plan of Reorganization"). Pepco's response to Mirant's supplemental brief was filed on July 22, 2005. The District Court has not yet set a hearing date regarding the Second Motion to Reject.

Mirant's opening brief to the Court of Appeals in its appeal of the District Court's March 1, 2005 and March 7, 2005 orders was filed June 1, 2005; the Creditors' Committee's opening brief was filed July 15, 2005 and the briefs of Pepco and other appellees are due on August 17, 2005.

Pepco is exercising all available legal remedies and vigorously opposing Mirant's attempt to reject the PPA-Related Obligations and other obligations under the Asset Purchase and Sale Agreement in order to protect the interests of its customers and shareholders. While Pepco believes that it has substantial legal bases to oppose the attempt to reject the agreements, the outcome of Mirant's efforts to reject the PPA-Related Obligations is uncertain.

If Mirant ultimately is successful in rejecting the PPA-Related Obligations, Pepco could be required to repay to Mirant, for the period beginning on the effective date of the rejection (which date could be prior to the date of the court's order granting the rejection and possibly as early as September 18, 2003) and ending on the date Mirant is entitled to cease its purchases of energy and capacity from Pepco, all amounts paid by Mirant to Pepco in respect of the PPA-Related Obligations, less an amount equal to the price at which Mirant resold the purchased energy and capacity. Pepco estimates that the amount it could be required to repay to Mirant in the unlikely event that September 18, 2003 is determined to be the effective date of rejection, is approximately $215.1 million as of August 1, 2005.

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Mirant has also indicated to the Bankruptcy Court that it will move to require Pepco to disgorge all amounts paid by Mirant to Pepco in respect of the PPA-Related Obligations, less an amount equal to the price at which Mirant resold the purchased energy and capacity, for the period July 14, 2003 (the date on which Mirant filed its bankruptcy petition) through rejection, if approved, on the theory that Mirant did not receive value for those payments. Pepco estimates that the amount it would be required to repay to Mirant on the disgorgement theory, in addition to the amounts described above, is approximately $22.5 million.

Any repayment by Pepco of amounts paid by Mirant would entitle Pepco to file a claim against the bankruptcy estate in an amount equal to the amount repaid. Pepco believes that, to the extent such amounts were not recovered from the Mirant bankruptcy estate, they would be recoverable as stranded costs from customers through distribution rates as described below.

The following are estimates prepared by Pepco of its potential future exposure if Mirant's attempt to reject the PPA-Related Obligations ultimately is successful. These estimates are based in part on current market prices and forward price estimates for energy and capacity, and do not include financing costs, all of which could be subject to significant fluctuation. The estimates assume no recovery from the Mirant bankruptcy estate and no regulatory recovery, either of which would mitigate the effect of the estimated loss. Pepco does not consider it realistic to assume that there will be no such recoveries. Based on these assumptions, Pepco estimates that its pre-tax exposure as of August 1, 2005 representing the loss of the future benefit of the PPA-Related Obligations to Pepco, is as follows:

If Pepco were required to purchase capacity and energy from FirstEnergy commencing as of August 1, 2005, at the rates provided in the PPA (with an average price per kilowatt hour of approximately 6.1 cents) and resold the capacity and energy at market rates projected, given the characteristics of the FirstEnergy PPA, to be approximately 5.6 cents per kilowatt hour, Pepco estimates that it would cost approximately $8.4 million for the remainder of 2005, the final year of the FirstEnergy PPA.

If Pepco were required to purchase capacity and energy from Panda commencing as of August 1, 2005, at the rates provided in the PPA (with an average price per kilowatt hour of approximately 16.5 cents), and resold the capacity and energy at market rates projected, given the characteristics of the Panda PPA, to be approximately 9.3 cents per kilowatt hour, Pepco estimates that it would cost approximately $14 million for the remainder of 2005, approximately $28 million in 2006, approximately $28 million in 2007, and approximately $28 million to $42 million annually thereafter through the 2021 contract termination date.

The ability of Pepco to recover from the Mirant bankruptcy estate in respect to the Mirant Pre-Petition Obligations and damages if the PPA-Related Obligations are successfully rejected will depend on whether Pepco's claims are allowed, the amount of assets available for distribution to the creditors of the Mirant companies determined to be liable for those claims, and Pepco's priority relative to other creditors. At the current stage of the bankruptcy proceeding, there is insufficient information to determine the amount, if any, that Pepco might be able to recover from the Mirant bankruptcy estate, whether the recovery would be in cash or another form of payment, or the timing of any recovery.

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If Mirant ultimately is successful in rejecting the PPA-Related Obligations and Pepco's full claim is not recovered from the Mirant bankruptcy estate, Pepco may seek authority from the MPSC and the District of Columbia Public Service Commission (DCPSC) to recover its additional costs. Pepco is committed to working with its regulatory authorities to achieve a result that is appropriate for its shareholders and customers. Under the provisions of the settlement agreements approved by the MPSC and the DCPSC in the deregulation proceedings in which Pepco agreed to divest its generation assets under certain conditions, the PPAs were to become assets of Pepco's distribution business if they could not be sold. Pepco believes that, if Mirant ultimately is successful in rejecting the PPA-Related Obligations, these provisions would allow the stranded costs of the PPAs that are not recovered from the Mirant bankruptcy estate to be recovered from Pepco's customers through its distributi on rates. If Pepco's interpretation of the settlement agreements is confirmed, Pepco expects to be able to establish the amount of its anticipated recovery as a regulatory asset. However, there is no assurance that Pepco's interpretation of the settlement agreements would be confirmed by the respective public service commissions.

If the PPA-Related Obligations are successfully rejected, and there is no regulatory recovery, Pepco will incur a loss; the accounting treatment of such a loss, however, would depend on a number of legal and regulatory factors.

Mirant's Fraudulent Transfer Claim

On July 13, 2005, Mirant filed a complaint in the Bankruptcy Court against Pepco alleging that Mirant's purchase of Pepco's generating assets in June 2000 for $2.65 billion constituted a fraudulent transfer. Mirant alleges in the complaint that it paid too much for Pepco's generating assets and that such overpayment constitutes a fraudulent transfer under applicable law, and contends that it is entitled to recover the alleged overpayment. The price paid by Mirant for Pepco's generating assets was determined at a commercial auction, in which Mirant was the highest bidder. The terms of the Asset Purchase and Sale Agreement were the result of an arm's-length negotiation between two sophisticated, independent companies. At all times during those negotiations, Mirant was represented by sophisticated financial advisors, legal counsel and other professionals. Moreover, the asset sale was approved by FERC and was reviewed by the MPSC and the DCPSC. Accordingly, Pepco believes M irant's complaint is entirely without merit and is vigorously contesting the claim.

The SMECO Agreement

As a term of the Asset Purchase and Sale Agreement, Pepco assigned to Mirant a facility and capacity agreement with Southern Maryland Electric Cooperative, Inc. (SMECO) under which Pepco was obligated to purchase the capacity of an 84-megawatt combustion turbine installed and owned by SMECO at a former Pepco generating facility (the SMECO Agreement). The SMECO Agreement expires in 2015 and contemplates a monthly payment to SMECO of approximately $.5 million. Pepco is responsible to SMECO for the performance of the SMECO Agreement if Mirant fails to perform its obligations thereunder. At this time, Mirant continues to make post-petition payments due to SMECO.

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agreement, any claim against the bankruptcy estate for damages made by SMECO (or by Pepco as subrogee) would be subject to the provisions of the Bankruptcy Code that limit the recovery of rejection damages by lessors. Pepco believes that there is no reasonable factual or legal basis to support Mirant's contention that the SMECO Agreement is a lease of real property. Litigation continues and the outcome of this proceeding cannot be predicted.

Mirant Plan of Reorganization

On January 19, 2005, Mirant filed its Plan of Reorganization and Disclosure Statement with the Bankruptcy Court (the Original Reorganization Plan) under which Mirant proposed to transfer all assets to "New Mirant" (an entity it proposed to create in the reorganization), with the exception of the PPA-Related Obligations. Mirant proposed that the PPA-Related Obligations would remain in "Old Mirant," which would be a shell entity as a result of the reorganization. On March 25, 2005, Mirant filed its First Amended Plan of Reorganization and First Amended Disclosure Statement (the Amended Reorganization Plan), in which Mirant abandoned the proposal that the PPA-Related Obligations would remain in "Old Mirant," but did not clarify how the PPA-Related Obligations would be treated.

On March 11, 2005, Mirant filed an application with FERC seeking approval for the internal transfers and corporate restructuring that will result from the Original Reorganization Plan. FERC approval for these transactions is required under Section 203 of the Federal Power Act. On April 1, 2005, Pepco filed a motion to intervene and protest at FERC in connection with this application. On the same date, the District of Columbia OPC also filed a motion to intervene and protest. Pepco, the District of Columbia OPC, the Maryland OPC and the MPSC filed pleadings arguing that the application was premature inasmuch as it was unclear whether the planned reorganization would be approved by the Bankruptcy Court and asking that FERC refrain from acting on the application.

On June 17, 2005, FERC issued anorder approving the planned restructuring outlined in the Original Reorganization Plan. While the FERC order has no direct impact on Pepco, the order included a discussion concerning the impact of the restructuring on Pepco's rates, with which Pepco disagrees. Pepco filed a motion for rehearing on July 18, 2005. Pepco cannot predict the outcome of its motion for rehearing.

Rate Proceedings

New Jersey

In February 2003, ACE filed a petition with the NJBPU to increase its electric distribution rates and its Regulatory Asset Recovery Charge (RARC) in New Jersey. In December 2003, the NJBPU issued an order that consolidated into the base rate proceeding (Phase I) outstanding issues from several other proceedings, including the recovery by ACE of $25.4 million of deferred restructuring costs related to the provision of BGS. Later in December 2003, ACE filed a Motion for Reconsideration in which it suggested that these additional issues be dealt with in a Phase II proceeding separate from the Phase I base rate proceeding.

On April 19, 2005, a settlement was reached among ACE, the staff of the NJBPU, the New Jersey Ratepayer Advocate and active intervenor parties that resolved issues in both the Phase I and Phase II proceedings. The NJBPU approved this settlement in an order dated May 26, 2005.

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The settlement allows for an increase in ACE's base rates of approximately $18.8 million, $2.8 million of which will come from an increase in RARC revenue collections each year for the next four years. The $16 million of the base rate increase, not related to RARC collections, will be collected annually from ACE's customers until such time as base rates change pursuant to another base rate proceeding. The $18.8 million increase in base rate revenue is offset by a base rate revenue decrease in a similar amount in total resulting from a change in depreciation rates, as discussed below, similar to changes adopted by the NJBPU for other New Jersey electric utility companies. Overall, the settlement provides for a net decrease in annual revenues of approximately $.3 million, consisting of a $3.1 million reduction of distribution revenues offset by the $2.8 million increase in RARC revenue collections discussed above. The settlement specifies an overall rate of return of 8.14% and pr ovides for a change in depreciation rates driven by a change in average service lives. In addition, the settlement provides for a change in depreciation technique from remaining life to whole life, including amortization of any calculated excess or deficiencies in the depreciation reserve. As a result of these changes, PHI and ACE each had a net excess depreciation reserve. Accordingly, PHI and ACE each recorded a regulatory liability in March 2005 by reducing its depreciation reserve by approximately $131 million. The regulatory liability will be amortized over 8.25 years and will result in a reduction of depreciation and amortization expense on PHI's and ACE's consolidated statements of earnings. While the impact of the settlement is essentially revenue and cash neutral to PHI and ACE, there is a positive annual pre-tax earnings impact to PHI and ACE of approximately $20 million.

With respect to Phase II issues, which included supply-related deferred costs, the settlement provides for a disallowance of $13.0 million previously recorded to such deferred accounts and specifies the recovery over four years of an adjusted deferred balance of approximately $116.8 million, including a portion of the $25.4 million of costs described above, offset by the return over one year of over-collected balances in certain other deferred accounts. The net result of these changes is that there will be no rate impact from the deferral account recoveries and credits for at least one year.

The settlement does not affect the existing appeal filed by ACE with the Appellate Division of the Superior Court of New Jersey (the NJ Superior Court) related to the July 2004 Final Decision and Order issued by the NJBPU in ACE's restructuring deferral proceeding before the NJBPU under the New Jersey Electric Discount and Energy Competition Act (EDECA), discussed below under "Restructuring Deferral."

Delaware

In October 2004, DPL submitted its annual Gas Cost Rate (GCR) filing to the Delaware Public Service Commission (DPSC). In its filing, DPL sought to increase its GCR by approximately 16.8% in anticipation of increasing natural gas commodity costs. The GCR, which permits DPL to recover its procurement gas costs through customer rates, became effective November 1, 2004 and is subject to refund pending evidentiary hearings. In addition, in November 2004, DPL filed a supplemental filing seeking approval to further increase GCR rates by an additional 6.5% effective December 29, 2004. The additional GCR increase became effective December 29, 2004 and, similarly, is subject to refund pending evidentiary hearings. The DPSC staff and the Division of Public Advocate filed their testimony on March 7, 2005 recommending full approval of the GCR changes being sought by DPL, including the revisions to the tariff in the original and supplemental filings. An evidentiary hearing was h eld on May 5,

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2005, at which both DPSC staff and the Division of Public Advocate testified that the rates sought by DPL should be approved as filed. On July 15, 2005, the Hearing Examiner released her written recommendation that the rates sought by DPL should be approved. A final order addressing both the November 1 and December 29 increases is expected in the third quarter of 2005.

Pursuant to the April 16, 2002 merger settlement agreement in Delaware, on May 4, 2005, DPL made a filing with the DPSC whereby DPL seeks approval of a proposed increase of approximately $6.2 million in electric transmission service revenues, or about 1.1% of total Delaware retail electric revenues. This proposed revenue increase is the Delaware retail portion of the increase in the "Delmarva zonal" transmission rates on file with FERC under the Open Access Transmission Tariff (OATT) of the PJM Interconnection, LLC (PJM). This level of revenue increase will decrease to the extent that competitive retail suppliers provide a supply and transmission service to retail customers. In that circumstance, PJM would charge the competitive retail supplier the PJM OATT rate for transmission service into the Delmarva zone and DPL's charges to the retail customer would exclude as a "shopping credit" an amount equal to the SOS supply charge and the transmission and ancillary charges that would otherwise be charged by DPL to the retail customer. DPL began collecting this rate change for service rendered on and after June 3, 2005, subject to refund.

Restructuring Deferral

Pursuant to a July 1999 summary order issued by the NJBPU under EDECA (which order was subsequently affirmed by a final decision and order issued in March 2001), ACE was obligated to provide BGS from August 1, 1999 to at least July 31, 2002 to retail electricity customers in ACE's service territory who did not choose a competitive energy supplier. The order allowed ACE to recover through customer rates certain costs incurred in providing BGS. ACE's obligation to provide BGS was subsequently extended to July 31, 2003. At the allowed rates, for the period August 1, 1999 through July 31, 2003, ACE's aggregate allowed costs exceeded its aggregate revenues from supplying BGS. These under-recovered costs were partially offset by a $59.3 million deferred energy cost liability existing as of July 31, 1999 (LEAC Liability) that was related to ACE's Levelized Energy Adjustment Clause and ACE's Demand Side Management Programs. ACE established a regulatory asset in an amount eq ual to the balance of under-recovered costs.

In August 2002, ACE filed a petition with the NJBPU for the recovery of approximately $176.4 million in actual and projected deferred costs relating to the provision of BGS and other restructuring related costs incurred by ACE over the four-year period August 1, 1999 through July 31, 2003. The deferred balance was net of the $59.3 million offset for the LEAC Liability. The petition also requested that ACE's rates be reset as of August 1, 2003 so that there would be no under-recovery of costs embedded in the rates on or after that date. The increase sought represented an overall 8.4% annual increase in electric rates and was in addition to the base rate increase discussed above. ACE's recovery of the deferred costs is subject to review and approval by the NJBPU in accordance with EDECA.

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Proceedings--New Jersey," transferred to ACE's then pending base rate case for further consideration approximately $25.4 million of the deferred balance, and (iv) estimated the overall deferral balance as of July 31, 2003 at $195 million, of which $44.6 million was disallowed recovery by ACE. In July 2004, the NJBPU issued its final order in the restructuring deferral proceeding. The final order did not modify the amount of the disallowances set forth in the July 2003 summary order, but did provide a much more detailed analysis of evidence and other information relied on by the NJBPU as justification for the disallowances. ACE believes the record does not justify the level of disallowance imposed by the NJBPU. In August 2004, ACE filed with the NJ Superior Court a Notice of Appeal related to the July 2004 final order. ACE's initial brief is due on August 18, 2005. Final reply briefs are due by October 10, 2005. ACE cannot predict the outcome of this appeal.

Divestiture Cases

District of Columbia

Final briefs on Pepco's District of Columbia divestiture proceeds sharing application were filed in July 2002 following an evidentiary hearing in June 2002. That application was filed to implement a provision of Pepco's DCPSC-approved divestiture settlement that provided for a sharing of any net proceeds from the sale of Pepco's generation-related assets. One of the principal issues in the case 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, 2005, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generation assets were approximately $6.5 million and $5.8 million, respectively. In March 2003, the Internal Revenue Service (IRS) is sued a notice of proposed rulemaking (NOPR) that is relevant to that principal issue. The NOPR would allow for the sharing of EDIT and ADITC related to divested assets with utility customers on a prospective basis and at the election of the taxpayer on a retroactive basis. Comments on the NOPR were filed by several parties in June 2003, and the IRS held a public hearing later in June 2003; however, no final rules have been issued. As a result of the NOPR, three of the parties in the divestiture case filed comments with the DCPSC urging the DCPSC to decide the tax issues now on the basis of the proposed rule. Pepco filed comments with the DCPSC in reply to those comments, in which Pepco stated that the courts have held and the IRS has stated that proposed rules are not authoritative and that no decision should be issued on the basis of proposed rules. Instead, Pepco argued that the only prudent course of action is for the DCPSC to await the issuance of final regulations relating to the tax issues and the n allow the parties to file supplemental briefs on the tax issues. Pepco cannot predict whether the IRS will adopt the regulations as proposed, make changes before issuing final regulations or decide not to adopt regulations. Other issues in the proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.

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District of Columbia jurisdictional transmission and distribution-related ADITC balance 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. As of June 30, 2005, the District of Columbia jurisdictional transmission and distribution related ADITC balance was approximately $5.7 million.

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 condition. It is uncertain when the DCPSC will issue a decision.

Maryland

Pepco filed its divestiture proceeds plan application in Maryland in April 2001. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that was raised in the D.C. case. See the discussion above under "Divestiture Cases - District of Columbia." As of June 30, 2005, the Maryland allocated portions of EDIT and ADITC associated with the divested generation assets were approximately $9.1 million and $10.4 million, respectively. Other issues deal with the treatment of certain costs as deductions from the gross proceeds of the divestiture. In November 2003, the Hearing Examiner in the Maryland proceeding issued a proposed order that concluded that Pepco's Maryland divestiture settlement agreement provided for a sharing between Pepco and customers of the EDIT and ADITC associated with the sold assets. Pepco believes that such a sharing would violate the normalization rules and would result in Pepco's inability to use accelerated depreciation on Maryland allocated or assigned property. If the proposed order is affirmed, Pepco would have to share with its Maryland customers, on an approximately 50/50 basis, the Maryland allocated portion of the generation-related EDIT,i.e., $9.1 million as of June 30, 2005, and the generation-related ADITC. If such sharing were to violate the normalization rules, Pepco, in addition to sharing with customers an amount equal to approximately 50 percent of the generation-related ADITC balance, would be unable to use accelerated depreciation on Maryland allocated or assigned property. Furthermore, Pepco would have to pay to the IRS an amount equal to Pepco's $10.4 million Maryland jurisdictional generation-related ADITC balance as of June 30, 2005, as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance as of the later of the date a MPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the MPSC order becomes op erative. As of June 30, 2005, the Maryland retail jurisdictional transmission and distribution related ADITC balance was $10.1 million. The Hearing Examiner decided all other issues in favor of Pepco, except for the determination that only one-half of the severance payments that Pepco included in its calculation of corporate reorganization costs should be deducted from the sales proceeds before sharing of the net gain between Pepco and customers. See also the disclosure above under "Divestiture Cases - District of Columbia" regarding the March 2003 IRS NOPR.

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Under Maryland law, if the proposed order is appealed to the MPSC, the proposed order is not a final, binding order of the MPSC and further action by the MPSC is required with respect to this matter. Pepco has appealed the Hearing Examiner's decision on the treatment of EDIT and ADITC and corporate reorganization costs to the MPSC. Pepco cannot predict what the outcome of the appeal will be or when the appeal might be decided. Pepco believes that its calculation of the Maryland customers' share of divestiture proceeds is correct. However, depending on the ultimate outcome of this proceeding, Pepco could be required to share with its customers approximately 50 percent of the EDIT and ADITC balances described above and make additional gain-sharing payments related to the disallowed severance payments. Such additional payments 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 results of oper ations 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 condition.

SOS, Default Service and BGS Proceedings

District of Columbia

For a history of Pepco's SOS proceeding before the DCPSC, please refer to Note (12), Commitments and Contingencies, to the Consolidated Financial Statements of PHI included in PHI's Annual Report on Form 10-K for the year ended December 31, 2004. The TPA with Mirant under which Pepco obtained the fixed-rate District of Columbia SOS supply ended on January 22, 2005, while the new SOS supply contracts with the winning bidders in the competitive procurement process began on February 1, 2005. Pepco procured power separately on the market for next-day deliveries to cover the period from January 23 through January 31, 2005, before the new District of Columbia SOS contracts began. Consequently, Pepco had to pay the difference between the procurement cost of power on the market for next-day deliveries and the current District of Columbia SOS rates charged to customers during the period from January 23 through January 31, 2005. In addition, because the new District of Columbi a SOS rates did not go into effect until February 8, 2005, Pepco had to pay the difference between the procurement cost of power under the new District of Columbia SOS contracts and the District of Columbia SOS rates charged to customers for the period from February 1 to February 7, 2005. The total amount of the difference is estimated to be approximately $8.7 million. This difference, however, was included in the calculation of the Generation Procurement Credit (GPC) for the District of Columbia for the period February 8, 2004 through February 7, 2005. The GPC provides for a sharing between Pepco's customers and shareholders, on an annual basis, of any margins, but not losses, that Pepco earned providing SOS in the District of Columbia during the four-year period from February 8, 2001 through February 7, 2005. Currently, based on the rates paid by Pepco to Mirant under the TPA Settlement, there is no customer sharing. However, in the event that Pepco were to ultimately realize a significant recove ry from the Mirant bankruptcy estate associated with the TPA Settlement, the GPC would be recalculated, and the amount of customer sharing with respect to such recovery would be reduced because of the $8.7 million loss being included in the GPC calculation.

Virginia

Under amendments to the Virginia Electric Utility Restructuring Act implemented in March 2004, DPL is obligated to offer Default Service to customers in Virginia for an indefinite period

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until relieved of that obligation by the Virginia State Corporation Commission (VSCC). DPL currently obtains all of the energy and capacity needed to fulfill its Default Service obligations in Virginia under a supply agreement with Conectiv Energy that commenced on January 1, 2005 and expires in May 2006 (the 2005 Supply Agreement). A prior agreement, also with Conectiv Energy, terminated effective December 31, 2004. DPL entered into the 2005 Supply Agreement after conducting a competitive bid procedure in which Conectiv Energy was the lowest bidder.

In October 2004, DPL filed an application with the VSCC for approval to increase the rates that DPL charges its Virginia Default Service customers to allow it to recover its costs for power under the new supply agreement plus an administrative charge and a margin. A VSCC order issued in November 2004 allowed DPL to put interim rates into effect on January 1, 2005, subject to refund if the VSCC subsequently determined the rate is excessive. The interim rates reflected an increase of 1.0247 cents per kilowatt hour (kwh) to the fuel rate, which provide for recovery of the entire amount being paid by DPL to Conectiv Energy, but did not include an administrative charge or margin, pending further consideration of this issue. Therefore, the November 2004 order also directed the parties to file memoranda concerning whether administrative costs and a margin are properly recovered through a fuel clause mechanism. Memoranda were filed by DPL, the VSCC staff and Virginia's Offic e of Attorney General. The VSCC ruled in January 2005 that the administrative charge and margin are base rate items not recoverable through a fuel clause. On March 25, 2005, the VSCC approved a settlement resolving all other issues and making the interim rates final, contingent only on possible future adjustment depending on the result of a related proceeding at FERC. However, in the VSCC proceeding addressing "Proposed Rules Governing Exemptions to Minimum Stay Requirements and Wires Charges," the VSCC staff recognized that DPL should be entitled to earn a reasonable margin related to hourly pricing customers. The size of any margin that may be allowed with respect to hourly priced customers has no current impact because DPL has no hourly priced customers in Virginia. DPL continues to maintain that a margin should be earned on all customer classes. DPL cannot predict the outcome of this proceeding.

In October 2004, Conectiv Energy made a filing with FERC requesting authorization to enter into a contract to supply power to an affiliate, DPL, under the 2005 Supply Agreement. In December 2004, FERC granted the requested authorization effective January 1, 2005, subject to refund and hearings on the narrow question whether, given the absence of direct VSCC oversight over the DPL competitive bid process, DPL unduly preferred its own affiliate, Conectiv Energy, in the design and implementation of the DPL competitive bid process or in the credit criteria and analysis applied. On June 8, 2005, Conectiv Energy entered into a stipulation with FERC staff and the Virginia Office of Attorney General resolving all issues regarding DPL's procurement process. The stipulation concludes that DPL did not favor Conectiv Energy in awarding it the 2005 Supply Agreement. As part of the stipulation, DPL sent a letter to FERC committing to use a third-party independent monitor in future Virginia solicitations. The Administrative Law Judge (ALJ) has certified the stipulation to FERC. DPL cannot predict what action FERC will take with respect to the stipulation and ALJ certification.

Delaware

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2006. The process used in Delaware consists of three separate stages. The Stage 1 process was constructed to allow the DPSC to determine by February 28, 2005 the fundamental issues related to the selection of an SOS supplier. Stage 2 would resolve issues relating to the process under which supply would be acquired by the SOS provider and the way in which SOS prices would be set and monitored. In Stage 3, these selection and pricing mechanisms would be implemented to determine the post-May 2006 SOS supplier and the post-May 2006 SOS price. On January 26, 2005, the DPSC staff issued a report recommending to the DPSC that DPL be selected as the SOS supplier, subject to further discussions as to how to establish SOS prices. On March 22, 2005, the DPSC issued an order approving DPL as the SOS provider at market rates after May 1, 2006, when DPL's current fixed rate POLR obligation ends. The DPSC also approved a structure whereby DPL will retain the SOS obligation for an indefinite period until changed by the DPSC, and will purchase the power supply required to satisfy its market rate SOS obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure. The DPSC will determine in the future the margin, if any, that DPL will be permitted to earn in conjunction with providing, and other terms and conditions regarding, SOS.

On July 18, 2005, the DPSC staff, the Division of the Public Advocate, the group representing DPL's industrial and commercial customers, Conectiv Energy and DPL filed with the Hearing Examiner a comprehensive settlement agreement covering all Stage 2 issues described above. The agreement calls for DPL to provide SOS to all classes, with no specified termination date for SOS. Two categories of SOS will exist: (i) a fixed price SOS available to all but the largest customers; and (ii) an Hourly Priced Service (HPS) for the largest customers, HPS being mandatory for General Service - Transmission voltage (GS-T) customers and offered as an option for General Service - Primary voltage (GS-P) customers. If approved, a competitive bid process will be used to procure the full requirements of customers eligible for a fixed-price SOS. In addition to the costs of capacity, energy, transmission, and ancillary services associated with the fixed-price SOS and HPS, DPL's initial rates w ould include a component referred to as the Reasonable Allowance for Retail Margin (RARM). Components of the RARM would include estimated incremental expenses, a $2.75 million return, a cash working capital allowance, and recovery with a return over 5 years of the capitalized costs of a billing system to be used for billing HPS customers. The $2.75 million return would be recovered through a 0.6 mill charge per kwh to the fixed-price SOS customers and flat, non-bypassable charges of $400 per month for GS-T customers and $150 per month for GS-P customers who elected the HPS form of SOS. All such costs are presumed by DPL to be recoverable, but are subject to audit; furthermore, no settlement can override the statutory requirement that costs not be the product of waste, bad faith or an abuse of discretion. The settlement proposes that there will be a true-up proceeding during the second year to establish SOS and HPS rates based on the year-one actual costs, quantities of SOS and HPS provided, and the amoun t of actual recovery on the $2.75 million return. After year two, the only elements of rates that would be trued-up are the differences between the billed retail rates and the costs paid to the winning bidders in competitive SOS proceedings. Parties, including DPL, would be permitted to initiate a proceeding with the DPSC to adjust rates prospectively to reflect changes in incremental costs or quantities sold.

In testimony filed on July 29, 2005, the settlement was contested by the intervenors in the case that did not sign the settlement agreement. A public hearing was held on August 1 and a formal evidentiary hearing before a Hearing Examiner was held on August 4, 2005. Briefs are due August 16, 2005. The procedural schedule currently provides for DPSC deliberations by late September 2005, with a written order in October. Potential modifications to the settlement

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are also being discussed with the contesting parties. DPL cannot predict the outcome of this proceeding.

New Jersey

Pursuant to a May 5, 2005 order from the NJBPU, on July 1, 2005 ACE along with the other three electric distribution companies in New Jersey, filed a proposal addressing the procurement of BGS for the period beginning June 1, 2006. The areas addressed in the July 1, 2005 filings include, but are not limited to: the type of procurement process, the size, make-up and pricing options for the Commercial and Industrial Energy Pricing class, and the level of the retail margin and corresponding utilization of the retail margin funds. ACE cannot predict the outcome of this proceeding.

Proposed Shut Down of B.L. England Generating Facility; Construction of Transmission Facilities

Pursuant to a September 2003 NJBPU order, ACE filed a report in April 2004 with the NJBPU recommending that the B.L. England generating facility be shut down. The report stated that the operation of the B.L. England facility was necessary at the time of the report to satisfy reliability standards, but that those reliability standards could also be satisfied in other ways. The report concluded that, based on B.L. England's current and projected operating costs resulting from compliance with more restrictive environmental requirements, the most cost-effective way in which to meet reliability standards is to shut down the B.L. England facility and construct additional transmission enhancements in southern New Jersey.

The terms of an April 26, 2004 preliminary settlement among PHI, Conectiv, ACE, the New Jersey Department of Environmental Protection (NJDEP) and the Attorney General of New Jersey, which are further discussed under "Preliminary Settlement Agreement with NJDEP," below, established emission limits for B.L. England's operations (which would become applicable on October 1, 2008 for Unit 1 and on May 1, 2009 for Unit 2 if B.L. England is not shut down) and required ACE to seek necessary approvals from agencies that may have jurisdiction to shut down and permanently cease operations at B.L. England by December 15, 2007, and to obtain approval to construct necessary substation and transmission facilities.

In letters dated May and September 2004 to PJM, ACE informed PJM of its intent, as owner of the B.L. England generating plant, to retire the entire plant (447 MW) on December 15, 2007. PJM completed its independent analysis to determine the upgrades required to eliminate any identified reliability problems resulting from the retirement of B.L. England and recommended that certain transmission upgrades be installed prior to the summer of 2008. ACE's independent assessment confirmed that the transmission upgrades identified by PJM are necessary to maintain reliability in the Atlantic zone after the retirement of B.L. England.

In November 2004, ACE made a filing with the NJBPU requesting the necessary approvals for construction of the transmission upgrades required to maintain reliability in the Atlantic zone after the retirement of B.L. England. The NJBPU issued an order on April 21, 2005, which unanimously approved the petition for the construction of the transmission upgrades, including the 230 kilovolt (kV) Cumberland to Dennis line, the138 kV Dennis to Corson line, and the 138 kV Cardiff to Lewis line. The approval states that these lines are necessary even if B.L. England does not shut down.

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The amount of the costs incurred by ACE to construct the recommended transmission upgrades that ACE would be permitted to recover from load serving entities that use ACE's transmission system would be subject to approval by FERC. The amount of construction costs that ACE would be permitted to recover from retail ratepayers would be determined in accordance with the treatment of transmission-related revenue requirements in retail rates under the jurisdiction of the appropriate state regulatory commission. ACE cannot predict how the recovery of such costs will ultimately be treated by the state regulatory commissions and, therefore, cannot predict the financial impact to ACE of installing the recommended transmission upgrades. However, ACE expects to begin construction of the appropriate transmission upgrades while final decisions by FERC and state regulatory commissions concerning the methodology for recovery of the costs of such construction are still pending.

In December 2004, ACE filed a petition with the NJBPU requesting that the NJBPU establish a proceeding that will consist of a Phase I and Phase II and that the procedural process for the Phase I proceeding require intervention and participation by all persons interested in the prudence of the decision to shut down B.L. England generating facility and the categories of stranded costs associated with shutting down and dismantling the facility and remediation of the site. ACE contemplates that Phase II of this proceeding, which would be initiated by an ACE filing in 2008 or 2009, would establish the actual level of prudently incurred stranded costs to be recovered from customers in rates.

ACE Auction of Generation Assets

On May 6, 2005, ACE announced that it would again auction its electric generation assets, including B.L. England. ACE intends to construct the transmission upgrades referred to above whether or not B.L. England is sold. The stranded costs already subject to securitization will not be affected by any sale of B.L. England. If B.L. England were sold, the remaining assets that may be eligible for recovery as stranded costs, subject to regulatory approval, could possibly include (depending on the assets included in the sale) land, boilerplate equipment (including waterwall tubing, equipment monitoring devices and air heater baskets) and turbogenerator equipment of approximately $9.1 million. ACE also intends to re-auction its other generation assets, including its ownership interest in the Keystone and Conemaugh generating stations. The competitive bidding process for these assets is being managed by an independent third party. The offering memorandum and associated document s for the three generation assets have been sent to potential bidders who have signed a confidentiality agreement and indicative bids were received on July 21, 2005. Any successful bid for B.L. England must include assumption of all environmental liabilities associated with the plant in accordance with the auction standards previously issued by the NJBPU.

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General Litigation

During 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. Of the approximately 250 remaining asbestos cases pending against Pepco, approximately 85 cases were filed after December 19, 2000, and have been tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement.

While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) exceeds $400 million, Pepco believes the amounts claimed by current plaintiffs are greatly exaggerated. The amount of total liability, if any, and any related insurance recovery cannot be determined at this time; however, based on information and relevant circumstances known at this time, Pepco does not believe these suits will have a material adverse effect on its financial condition. However, if an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco's and PHI's results of operations.

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.

In May 2004, the U.S. Department of Justice (DOJ) invited DPL to enter into pre-filing negotiations in connection with DPL's alleged liability under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 at the Diamond State Salvage site in Wilmington, Delaware. In February 2005, DPL entered into a de minimis consent decree with the United States, which the U.S. District Court approved on June 24, 2005. The consent decree required DPL to pay $144,000 as reimbursement of the government's response costs, resolved DPL's alleged liability, and provided DPL with a covenant not to sue from the United States and protection from third-party claims for contribution.

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In July 2004, DPL entered into an Administrative Consent Order with the Maryland Department of the Environment (MDE) to perform a Remedial Investigation/Feasibility Study (RI/FS) to further identify the extent of soil, sediment and ground and surface water contamination related to former manufactured gas plant (MGP) operations at the Cambridge, Maryland site on DPL-owned property and to investigate the extent of MGP contamination on adjacent property. The costs for completing the RI/FS for this site are approximately $300,000, approximately $50,000 of which will be expended in 2005. The costs of cleanup resulting from the RI/FS will not be determinable until the RI/FS is completed and an agreement with respect to cleanup is reached with the MDE. Due to project delays, DPL now expects that the completion date for the RI/FS will be in the fourth quarter of 2005.

In October 1995, Pepco and DPL each received notice from the Environmental Protection Agency (EPA) that it, along with several hundred other companies, might be a potentially responsible party (PRP) in connection with the Spectron Superfund Site in Elkton, Maryland. The site was operated as a hazardous waste disposal, recycling and processing facility from 1961 to 1988.

In August 2001, Pepco entered into a consent decree for de minimis parties with EPA to resolve its liability at the Spectron site. Under the terms of the consent decree, which was approved by the U.S. District Court for the District of Maryland in March 2003, Pepco made de minimis payments to the United States and a group of PRPs. In return, those parties agreed not to sue Pepco for past and future costs of remediation at the site and the United States will also provide protection against third-party claims for contributions related to response actions at the site. The consent decree does not cover any damages to natural resources. However, Pepco believes that any liability that it might incur due to natural resource damage at this site would not have a material adverse effect on its financial condition or results of operations. In April 1996 DPL, with numerous other PRPs, entered into an administrative order of consent with EPA to perform an RI/FS at the Spectron site. In February 2003, the EPA informed DPL that it will have no future liability for contribution to the remediation of the site.

In the early 1970s, both Pepco and DPL sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a nonaffiliated company. In December 1987, Pepco and DPL were notified by EPA that they, along with a number of other utilities and non-utilities, were PRPs in connection with the PCB contamination at the site.

In October 1994, an RI/FS including a number of possible remedies was submitted to the EPA. In December 1997, the EPA issued a Record of Decision that set forth a selected remedial action plan with estimated implementation costs of approximately $17 million. In June 1998, the EPA issued a unilateral administrative order to Pepco and 12 other PRPs to conduct the design and actions called for in its decision. In May 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. In October 2003, the bankruptcy court confirmed a reorganization plan that incorporates the terms of a settlement among the debtors, the United States and a group of utility PRPs including Pepco. Under the settlement, the reorganized entity/site owner will pay a total of $13.25 million to remediate the site.

As of May 1, 2005, Pepco had accrued $1.7 million to meet its liability for a remedy at the Metal Bank/Cottman Avenue site. At the present time, it is not possible to estimate the total

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extent of EPA's administrative and oversight costs or the expense associated with a site remedy ultimately implemented. However, Pepco believes that its liability at this site will not have a material adverse effect on its financial condition or results of operations.

In 1999, DPL entered into a de minimis settlement with EPA and paid approximately $107,000 to resolve its liability for cleanup costs at the Metal Bank/Cottman Avenue site. The de minimis settlement did not resolve DPL's responsibility for natural resource damages, if any, at the site. DPL believes that any liability for natural resource damages at this site will not have a material adverse effect on its financial condition or results of operations.

In June 1992, EPA identified ACE as a PRP at the Bridgeport Rental and Oil Services Superfund Site in Logan Township, New Jersey. In September 1996, ACE along with other PRPs signed a consent decree with EPA and NJDEP to address remediation of the site. ACE's liability is limited to 0.232 percent of the aggregate remediation liability and thus far ACE has made contributions of approximately $105,000. Based on information currently available, ACE may be required to contribute approximately an additional $100,000. ACE believes that its liability at this site will not have a material adverse effect on its financial condition or results of operations.

In November 1991, NJDEP identified ACE as a PRP at the Delilah Road Landfill site in Egg Harbor Township, New Jersey. In 1993, ACE, along with other PRPs, signed an administrative consent order with NJDEP to remediate the site. The soil cap remedy for the site has been completed and the NJDEP conditionally approved the report submitted by the parties on the implementation of the remedy in January 2003. In March 2004, NJDEP approved a Ground Water Sampling and Analysis Plan. The results of groundwater monitoring over the first year of this ground water sampling plan will help to determine the extent of post-remedy operation and maintenance costs. In March 2003, EPA demanded from the PRP group reimbursement for EPA's past costs at the site, totalling $168,789. The PRP group objected to the demand for certain costs, but agreed to reimburse EPA approximately $19,000. Based on information currently available, ACE may be required to contribute approximately an additional $62 6,000. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial condition or results of operations.

Preliminary Settlement Agreement with the NJDEP

In an effort to address NJDEP's concerns regarding ACE's compliance with New Source Review (NSR) requirements at B.L. England, on April 26, 2004, PHI, Conectiv and ACE entered into a preliminary settlement agreement with NJDEP and the Attorney General of New Jersey. The preliminary settlement agreement outlines the basic parameters for a definitive agreement to resolve ACE's NSR liability at B.L. England and various other environmental issues at ACE and Conectiv Energy facilities in New Jersey. Among other things, the preliminary settlement agreement provides that:

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	obtain the required regulatory approvals), B.L. England Unit 1 would be required to comply with stringent sulfur dioxide (SO₂), nitrogen oxide (NOx) and particulate matter emissions limits set forth in the preliminary settlement agreement by October 1, 2008, and B.L. England Unit 2 would be required to comply with these emissions limits by May 1, 2009. If ACE does not either shut down the B.L. England facility by December 15, 2007 or satisfy the emissions limits applicable in the event shut down is not so completed, ACE would be required to pay significant monetary penalties.
·	to address ACE's appeal of NJDEP actions relating to NJDEP's July 2001 denial of ACE's request to renew a permit variance from sulfur-in-fuel requirements under New Jersey regulations, effective through July 30, 2001, that authorized Unit 1 at B.L. England generating facility to burn bituminous coal containing greater than 1% sulfur, ACE will be permitted to combust coal with a sulfur content of greater than 1% at the B.L. England facility in accordance with the terms of B.L. England's current permit until December 15, 2007 and NJDEP will not impose new, more stringent short-term SO₂ emissions limits on the B.L. England facility during this period. By letter dated July 13, 2005, NJDEP extended, until October 30, 2005, the deadline for ACE to file an application to renew its current fuel authorization for the B.L. England generating plant, which is scheduled to expire on July 30, 2006.
·	to resolve any possible civil liability (and without admitting liability) for violations of the permit provisions of the New Jersey Air Pollution Control Act (APCA) and the Prevention of Significant Deterioration provisions of the Federal Clean Air Act (CAA) relating to modifications that may have been undertaken at the B.L. England facility, ACE paid a $750,000 civil penalty to NJDEP on June 1, 2004. To compensate New Jersey for other alleged violations of the APCA and/or the CAA, ACE will undertake environmental projects valued at $2 million, which are beneficial to the state of New Jersey and approved by the NJDEP in a consent order or other final settlement document.
·	ACE will submit all federally required studies and complete construction of facilities, if any, necessary to satisfy the EPA's new cooling water intake structure regulations in accordance with the schedule that NJDEP established in the recent renewal of the New Jersey Pollutant Discharge Elimination System permit for the B.L. England facility. The schedule takes into account ACE's agreement, provided that all regulatory approvals are obtained, to shut down the B.L. England facility by December 15, 2007.
·	to resolve any possible civil liability (and without admitting liability) for natural resource damages resulting from groundwater contamination at the B.L. England facility, Conectiv Energy's Deepwater generating facility and ACE's operations center near Pleasantville, New Jersey, ACE and Conectiv will pay NJDEP $674,162 or property of equivalent value and will remediate the groundwater contamination at all three sites. If subsequent data indicate that groundwater contamination is more extensive than indicated in NJDEP's preliminary analysis, NJDEP may seek additional compensation for natural resource damages.

The preliminary settlement agreement provides that the parties will work toward a consent order or other final settlement document that reflects the terms of the preliminary settlement agreement. ACE, Conectiv and PHI continue to negotiate with the NJDEP the terms of a consent order or other final settlement document.

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Federal Tax Treatment of Cross-Border Leases

PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which as of June 30, 2005 had a book value of approximately $1.2 billion and from which PHI currently derives approximately $55 million per year in tax benefits in the form of interest and depreciation deductions. The American Jobs Creation Act of 2004 imposed new passive loss limitation rules that apply prospectively to leases (including cross-border leases) entered into after March 12, 2004 with tax-indifferent parties (i.e., municipalities and tax exempt or governmental entities). All of PCI's cross-border energy leases are with tax-indifferent parties and were entered into prior to 2004. Although this legislation is prospective in nature and does not affect PCI's existing cross-border energy leases, it does not prohibit the IRS from challenging prior leasing transactions. In this regard, on February 11, 2005, the Treasury Department and IRS issued Notice 2005-13 informing taxpayers th at the IRS intends to challenge on various grounds the purported tax benefits claimed by taxpayers entering into certain sale-leaseback transactions with tax-indifferent parties, including those entered into on or prior to March 12, 2004 (the "Notice"). In addition, on June 29, 2005 the IRS published a Coordinated Issue Paper with respect to such transactions. PCI's cross-border energy leases are similar to those sale-leaseback transactions described in the Notice and the Coordinated Issue Paper.

PCI's leases have been under examination by the IRS as part of the normal PHI tax audit. On May 4, 2005, the IRS issued a Notice of Proposed Adjustment to PHI that challenges the tax benefits realized from interest and depreciation deductions claimed by PHI with respect to these leases for the tax years 2001 and 2002. The tax benefits claimed by PHI with respect to these leases from 2001 through the second quarter of 2005 were approximately $203 million. The ultimate outcome of this issue is uncertain; however, if the IRS prevails, PHI would be subject to additional taxes, along with interest and possibly penalties on the additional taxes, which could have a material adverse effect on PHI's results of operations and cash flow.

PHI believes that its tax position related to these transactions was proper based on applicable statutes, regulations and case law, and intends to contest any adjustments proposed by the IRS; however, there is no assurance that PHI's position will prevail.

Under SFAS No. 13, as currently interpreted, a settlement with the IRS that results in a deferral of tax benefits that does not change the total estimated net income from a lease does not require an adjustment to the book value of the lease. However, if the IRS were to disallow, rather than require the deferral of, certain tax deductions related to PHI's leases, PHI would be required to adjust the book value of the leases and record a charge to earnings equal to the repricing impact of the disallowed deductions. Such a charge to earnings, if required, is likely to have a material adverse effect on PHI's results of operations for the period in which the charge is recorded.

In July 2005, the FASB released a Proposed Staff position that would amend SFAS No. 13 and require a lease to be repriced and the book value adjusted when there is a change or probable change in the timing of tax benefits. Under this proposal, a material change in the timing of cash flows under PHI's cross-border leases as the result of a settlement with the IRS also would require an adjustment to the book value. If adopted, the application of this guidance could result in a material adverse effect on PHI's results of operations even if a resolution with the IRS is limited to a deferral of the tax benefits realized by PCI from its leases.

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

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

As of June 30, 2005, 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 fair value of these commitments and obligations was not required to be recorded in Pepco Holdings' Consolidated Balance Sheets; however, certain energy marketing obligations of Conectiv Energy were recorded. The commitments and obligations, in millions of dollars, were as follows:

	Guarantor
		PHI		DPL		ACE		Other		Total
Energy marketing obligations of Conectiv Energy (1)	$	154.0	$	-	$	-	$	-	$	154.0
Energy procurement obligations ofPepco Energy Services (1)		6.9		-		-		-		6.9
Standby letters of credit of Pepco Holdings (2)		.5		-		-		-		.5
Guaranteed lease residual values (3)		.4		3.2		3.0		.3		6.9
Loan agreement (4)		13.1		-		-		-		13.1
Other (5)		19.0		-		-		2.7		21.7
Total	$	193.9	$	3.2	$	3.0	$	3.0	$	203.1

1.	Pepco Holdings has contractual commitments for performance and related payments of Conectiv Energy and Pepco Energy Services to counterparties related to routine energy sales and procurement obligations, including requirements under BGS contracts entered into with ACE.
2.	Pepco Holdings has issued standby letters of credit of $.5 million on behalf of subsidiaries' operations related to Conectiv Energy's competitive energy activities and third party construction performance. These standby letters of credit were put into place in order to allow the subsidiaries the flexibility needed to conduct business with counterparties without having to post substantial cash collateral. While the exposure under these standby letters of credit is $.5 million, Pepco Holdings does not expect to fund the full amount.
3.	Subsidiaries of Pepco Holdings have guaranteed residual values in excess of fair value related to certain equipment and fleet vehicles held through lease agreements. As of June 30, 2005, obligations under the guarantees were approximately $6.9 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.
4.	Pepco Holdings has issued a guarantee on the behalf of a subsidiary's 50% unconsolidated investment in a limited liability company for repayment borrowings under a loan agreement of approximately $13.1 million.

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5.	Other guarantees consist of:
	·	Pepco Holdings has performance obligations of $.5 million relating to obligations to third party suppliers of equipment.
	·	Pepco Holdings has guaranteed payment of a bond issued by a subsidiary of $14.9 million. Pepco Holdings does not expect to fund the full amount of the exposure under the guarantee.
	·	Pepco Holdings has guaranteed a subsidiary building lease of $3.6 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. As of June 30, 2005, the guarantees cover the remaining $2.7 million in rental obligations.

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 indemniti es.

Dividends

On July 28, 2005, Pepco Holdings' Board of Directors declared a dividend on common stock of 25 cents per share payable September 30, 2005, to shareholders of record on September 10, 2005.

(5) USE OF DERIVATIVES IN ENERGY AND INTEREST RATE HEDGING ACTIVITIES

PHI accounts for its derivative activities in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) as amended by subsequent pronouncements. See Note (2), Accounting for Derivatives, and Note (13), Use of Derivatives in Energy and Interest Rate Hedging Activities, to the Consolidated Financial Statements of PHI included in PHI's Annual Report on Form 10-K for the year ended December 31, 2004, for a discussion of the accounting treatment of the derivatives used by PHI and its subsidiaries.

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The table below provides detail on effective cash flow hedges under SFAS 133 included in PHI's consolidated balance sheet as of June 30, 2005. Under SFAS 133, cash flow hedges are marked-to-market on the balance sheet with corresponding adjustments to Accumulated Other Comprehensive Income (AOCI) or Accumulated Other Comprehensive Loss (AOCL). The data in the table indicates the magnitude of the effective cash flow hedges by hedge type (i.e., other energy commodity and interest rate hedges), maximum term, and portion expected to be reclassified to earnings during the next 12 months.

Cash Flow Hedges Included in AOCI/(AOCL) As of June 30, 2005
(Dollars in Millions)
Contracts		AOCI/(AOCL) After Tax (1)			Portion Expected to be Reclassified to Earnings during the Next 12 Months			Maximum Term
Other Energy Commodity		$	10.4		$	23.0		57 months
Interest Rate			(43.7	)		(7.3	)	326 months
Total		$	(33.3	)	$	15.7

(1)	AOCL as of June 30, 2005, includes $(4.1) million for an adjustment for minimum pension liability. This adjustment is not included in this table as it is not a cash flow hedge.

The following table shows, in millions of dollars, the competitive energy pre-tax gain (loss) recognized in earnings for cash flow hedge ineffectiveness for the three and six months ended June 30, 2005 and 2004, and where they were reported in PHI's consolidated statements of earnings during the periods.

	Three Months Ended					Six Months Ended
		2005		2004			2005			2004
Operating Revenue	$	1.3	$	(3.9	)	$	2.4		$	(6.7	)
Fuel and Purchased Energy		-		1.8			(.9	)		.1
Total	$	1.3	$	(2.1	)	$	1.5		$	(6.6	)

For the three and six months ended June 30, 2005 and 2004, there were no forecasted hedged transactions deemed to be no longer probable.

In connection with their other energy commodity activities and discontinued proprietary trading activities, PHI's competitive energy segments hold certain derivatives that do not qualify as hedges. Under SFAS 133, these derivatives are marked-to-market through earnings with corresponding adjustments on the balance sheet. The pre-tax gains (losses) on these derivatives are summarized in the following table, in millions of dollars, for the three and six months ended June 30, 2005 and 2004.

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	Three Months Ended				Six Months Ended
		2005		2004		2005		2004
Proprietary Trading	$	.1	$	-	$	.1	$	(.2	)
Other Energy Commodity		4.6		7.0		6.3		8.2
Total	$	4.7	$	7.0	$	6.4	$	8.0

(6)CHANGES IN ACCOUNTING ESTIMATES

During the second quarter of 2005, DPL and ACE each recorded the impact of reductions in estimated unbilled revenue, primarily reflecting an increase in the estimated amount of power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). These changes in accounting estimates reduced second quarter earnings by approximately $7.4 million (4 cents per share, for PHI), of which $1.0 million was attributable to DPL and $6.4 million was attributable to for ACE.

(7)SUBSEQUENT EVENTS

Sale of Buzzard Point Property

On July 18, 2005, John Akridge Development Company (Akridge) definitively committed to purchase 384,051 square feet of excess non-utility land owned by Pepco located at Buzzard Point in the District of Columbia under the terms of a tentative sale agreement entered into by Akridge, PHI and Pepco on June 3, 2005, and subsequently amended. Consummation of the sale is subject to customary closing conditions and closing is scheduled to occur in August 2005. The sale price of the land is $75 million in cash and is expected to result in an after-tax gain of approximately $38 to $42 million that will be recorded by Pepco in the third quarter, upon closing. The sale agreement provides that Akridge will release Pepco from, and indemnify Pepco for, substantially all environmental liabilities associated with the land, except that Pepco will retain liability for claims by third parties arising from the release, if any, of hazardous substances from the land onto adjacent property occurr ing before the closing of the sale.

IRS Revenue Ruling

During 2001, Pepco, DPL, and ACE changed their methods of accounting with respect to capitalizable construction costs for income tax purposes, which allow the companies to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through June 30, 2005, these accelerated deductions have generated approximately $279 million (consisting of $119 million for Pepco, $91 million for DPL, and $69 million for ACE) in tax cash flow benefits for the companies, primarily attributable to their 2001 tax returns. On August 2, 2005, the IRS issued Revenue Ruling 2005-53 (the Ruling) that will limit the ability of the companies to utilize this method of accounting. Under the Ruling, Pepco, DPL, and ACE may have to recapitalize and depreciate a portion of these expenses and repay a portion of the past income tax benefits, along with interest thereon.

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PHI believes that its tax position was appropriate based on applicable statutes, regulations, and case law in effect at the time the companies made the change in accounting method for income tax purposes. However, there is no assurance that PHI's position will prevail.

The tax benefits derived from the change in accounting method have been accounted for as temporary differences in determining PHI's deferred income tax balances for financial reporting purposes. Consequently, the repayment of the tax benefits, if required, would affect cash flows and deferred income tax balances, but would not affect earnings, other than a charge for the accrual of related interest.

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POTOMAC ELECTRIC POWER COMPANY STATEMENTS OF EARNINGS (Unaudited)
	Three Months Ended June 30,						Six Months Ended June 30,
		2005			2004			2005			2004
		(Millions of Dollars)

Operating Revenues	$	396.1		$	461.2		$	821.6		$	830.8

Operating Expenses
Fuel and purchased energy		179.0			233.3			395.4			407.0
Other operation and maintenance		64.8			63.4			131.3			130.5
Depreciation and amortization		39.8			42.2			79.6			86.1
Other taxes		60.3			58.7			126.1			115.2
Gain on sale of assets		(2.8	)		-			(2.8	)		(6.6	)
Total Operating Expenses		341.1			397.6			729.6			732.2

Operating Income		55.0			63.6			92.0			98.6

Other Income (Expenses)
Interest and dividend income		-			.1			.5			.1
Interest expense		(19.9	)		(20.2	)		(38.9	)		(40.4	)
Other income		6.4			1.6			8.9			3.0
Other expenses		-			(.2	)		(.4	)		(.7	)
Total Other Expenses, Net		(13.5	)		(18.7	)		(29.9	)		(38.0	)

Income Before Income Tax Expense		41.5			44.9			62.1			60.6

Income Tax Expense		17.6			18.8			26.7			25.0

Net Income		23.9			26.1			35.4			35.6

Dividends on Redeemable Serial Preferred Stock		.3			.4			.6			.8

Earnings Available for Common Stock		23.6			25.7			34.8			34.8

Retained Earnings at Beginning of Period		492.7			502.6			496.4			505.3

Dividend of Investment to Pepco Holdings		-			(2.1	)		-			(2.1	)

Dividends paid to Pepco Holdings		-			(30.4	)		(14.9	)		(42.2	)

Retained Earnings at End of Period	$	516.3		$	495.8		$	516.3		$	495.8


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

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POTOMAC ELECTRIC POWER COMPANY BALANCE SHEETS (Unaudited)
	June 30,			December 31,
ASSETS		2005			2004
	(Millions of Dollars)
CURRENT ASSETS
Cash and cash equivalents	$	187.7		$	1.5
Accounts receivable, less allowance for uncollectible accounts of $18.3 million and $20.1 million, respectively		345.3			317.5
Materials and supplies-at average cost		39.0			38.2
Prepaid expenses and other		6.0			6.8
Total Current Assets		578.0			364.0

INVESTMENTS AND OTHER ASSETS
Regulatory assets		136.4			125.7
Prepaid pension expense		166.2			171.1
Other		138.2			129.9
Total Investments and Other Assets		440.8			426.7

PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		4,925.2			4,869.4
Accumulated depreciation		(2,001.1	)		(1,937.8	)
Net Property, Plant and Equipment		2,924.1			2,931.6

TOTAL ASSETS	$	3,942.9		$	3,722.3

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

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POTOMAC ELECTRIC POWER COMPANY BALANCE SHEETS (Unaudited)
	June 30,			December 31,
LIABILITIES AND SHAREHOLDER'S EQUITY		2005			2004
	(Millions of dollars, except shares)

CURRENT LIABILITIES
Short-term debt	$	175.0		$	114.0
Accounts payable and accrued liabilities		166.4			133.9
Accounts payable to associated companies		45.3			25.5
Capital lease obligations due within one year		4.9			4.7
Taxes accrued		65.0			50.9
Interest accrued		22.4			22.0
Other		82.7			83.6
Total Current Liabilities		561.7			434.6

DEFERRED CREDITS
Regulatory liabilities		105.1			126.7
Income taxes		711.4			711.9
Investment tax credits		17.6			18.6
Other post-retirement benefit obligation		46.4			43.8
Other		34.3			37.4
Total Deferred Credits		914.8			938.4

LONG-TERM LIABILITIES
Long-term debt		1,297.9			1,198.3
Capital lease obligations		118.9			121.3
Total Long-Term Liabilities		1,416.8			1,319.6

COMMITMENTS AND CONTINGENCIES (NOTE 4)

SERIAL PREFERRED STOCK		27.0			27.0

SHAREHOLDER'S EQUITY
Common stock, $.01 par value, authorized 400,000,000 shares, issued 100 shares		-			-
Premium on stock and other capital contributions		507.5			507.5
Capital stock expense		(.5	)		(.5	)
Accumulated other comprehensive loss		(.7	)		(.7	)
Retained earnings		516.3			496.4
Total Shareholder's Equity		1,022.6			1,002.7

TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$	3,942.9		$	3,722.3

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

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POTOMAC ELECTRIC POWER COMPANY STATEMENTS OF CASH FLOWS (Unaudited)
	Six Months Ended June 30,
		2005			2004
	(Millions of Dollars)
OPERATING ACTIVITIES
Net income	$	35.4		$	35.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		79.6			86.1
Gain on sale of asset		(2.8	)		(6.6	)
Deferred income taxes		2.8			12.4
Regulatory assets, net		(27.5	)		(23.0	)
Changes in:
Accounts receivable		(27.8	)		(66.1	)
Accounts payable and accrued liabilities		50.8			18.2
Interest and taxes accrued		14.5			8.0
Other changes in working capital		-			21.6
Net other operating activities		(1.9	)		(1.9	)
Net Cash From Operating Activities		123.1			84.3

INVESTING ACTIVITIES
Net investment in property, plant and equipment		(81.3	)		(96.4	)
Proceeds from sale of assets		2.8			22.0
Other investing activity		.3			-
Net Cash Used By Investing Activities		(78.2	)		(74.4	)

FINANCING ACTIVITIES
Dividends to Pepco Holdings		(14.9	)		(42.2	)
Dividends paid on preferred stock		(.6	)		(.8	)
Issuances of long-term debt		175.0			275.0
Reacquisition of long-term debt		-			(210.0	)
Repayment of short-term debt, net		(14.0	)		(22.0	)
Net other financing activities		(4.2	)		(9.0	)
Net Cash From (Used By) Financing Activities		141.3			(9.0	)

Net Increase in Cash and Cash Equivalents		186.2			.9
Cash and Cash Equivalents at Beginning of Period		1.5			6.8

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	187.7		$	7.7

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

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NOTES TO UNAUDITED 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 and Montgomery Counties in suburban Maryland. Additionally, Pepco provides Standard Offer Service, 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. Pepco's service territory covers approximately 640 square miles and has a population of approximately 2 million. Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (Pepco Holdings or PHI). Because PHI is a public utility holding company registered under the Public Utility Holding Company Act of 1935 (PUHCA), the relationship between PHI and Pepco and certain activities of Pepco are subject to the regulatory oversight of the Securities and Exchange Commission (SEC) under PUHCA.

(2) ACCOUNTING POLICY, PRONOUNCEMENTS, AND OTHER DISCLOSURES

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 SEC, 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, 2004. In the opinion of Pepco's management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to fairly state Pepco's financial condition as of June 30, 2005, its results of operations for the three and six months ended June 30, 2005, and its cash flows for the six months ended June 30, 2005, in accordance with GAAP. Interim results for the three and six months ended June 30, 2005 may not be indicativ e of results that will be realized for the full year ending December 31, 2005 since the sales of electric energy are seasonal. Additionally, certain prior period balances have been reclassified in order to conform to current period presentation.

Adjustment to Pepco's First Quarter 2005 Unbilled Revenue

In the second quarter of 2005, Pepco recorded an adjustment to correct the unbilled revenue amount that was reported in the first quarter of 2005. This adjustment reduced Pepco's second quarter earnings by $4.4 million. The adjustment had no impact on earnings for the six months ended June 30, 2005.

FIN 45

As of June 30, 2005, Pepco did not have material obligations under guarantees or indemnifications issued or modified after December 31, 2002, which are required to be recognized as liabilities on its balance sheets.

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FIN 46R

Due to a variable element in the pricing structure of Pepco's purchase power agreement (Panda PPA) with Panda-Brandywine, L.P. (Panda), Pepco potentially assumes the variability in the operations of the plants of this entity and therefore has a variable interest in the entity. As required by FIN 46R, Pepco continued to conduct exhaustive efforts to obtain information from this entity, but was unable to obtain sufficient information to conduct the analysis required under FIN 46R to determine whether the entity was a variable interest entity or if Pepco was the primary beneficiary. As a result, Pepco has applied the scope exemption from the application of FIN 46R for enterprises that have conducted exhaustive efforts to obtain the necessary information.

Power purchases related to the Panda PPA for the three months ended June 30, 2005 and 2004 were approximately $20 million and $19 million, respectively, and for the six months ended June 30, 2005 and 2004 were approximately $39 million in each period. Pepco's exposure to loss under the Panda PPA is discussed in Note (4), Commitments and Contingencies, under "Relationship with Mirant Corporation."

Components of Net Periodic Benefit Cost/(Income)

The following Pepco Holdings' information is for the three months ended June 30, 2005 and 2004.

		Pension Benefits						Other Post-Retirement Benefits
		2005			2004			2005			2004
	(In Millions)
Service cost	$	9.6		$	8.4		$	2.1		$	2.4
Interest cost		23.6			23.5			8.4			8.3
Expected return on plan assets		(32.1	)		(32.3	)		(2.9	)		(2.8	)
Amortization of prior service cost		.3			.3			(.9	)		-
Amortization of net loss		2.7			(1.3	)		3.4			3.1
Net periodic benefit cost/(income)	$	4.1		$	(1.4	)	$	10.1		$	11.0

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The following Pepco Holdings' information is for the six months ended June 30, 2005 and 2004.

		Pension Benefits						Other Post-Retirement Benefits
		2005			2004			2005			2004
	(In Millions)
Service cost	$	19.0		$	18.0		$	4.2		$	4.8
Interest cost		47.9			47.3			16.8			16.7
Expected return on plan assets		(62.8	)		(62.1	)		(5.4	)		(5.7	)
Amortization of prior service cost		.6			.5			(1.9	)		-
Amortization of net loss		5.2			3.3			5.9			6.2
Net periodic benefit cost	$	9.9		$	7.0		$	19.6		$	22.0

Pension

The 2005 pension net periodic benefit cost for the three months ended June 30, of $4.1 million includes $2.5 million for Pepco. The 2005 pension net periodic benefit cost for the six months ended June 30, of $9.9 million includes $5.1 million for Pepco. The remaining pension net periodic benefit cost is for other PHI subsidiaries. The 2004 pension net periodic benefit cost/(income) for the three months ended June 30, of $(1.4) million includes $.2 million for Pepco. The 2004 pension net periodic benefit cost for the six months ended June 30, of $7.0 million includes $3.7 million for Pepco. The remaining pension net periodic benefit cost is for other PHI subsidiaries.

The six months ended June 30, 2005 pension net periodic benefit cost reflects a reduction in the expected return on assets assumption from 8.75% to 8.50% effective January 1, 2005.

Pension Contributions

Other Post-Retirement Benefits

The 2005 other post-retirement net periodic benefit cost for the three months ended June 30, of $10.1 million includes $6.0 million for Pepco. The 2005 other post-retirement net periodic benefit cost for the six months ended June 30, of $19.6 million includes $9.0 million for Pepco. The remaining other post-retirement net periodic benefit cost is for other PHI subsidiaries. The

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2004 other post-retirement net periodic benefit cost for the three months ended June 30, of $11.0 million includes $4.5 million for Pepco. The 2004 other post-retirement net periodic benefit cost for the six months ended June 30, of $22.0 million includes $9.0 million for Pepco. The remaining other post-retirement net periodic benefit cost is for other PHI subsidiaries.

The six months ended June 30, 2005 other post-retirement net periodic benefit cost reflects a reduction in the expected return on assets assumption from 8.75% to 8.50% effective January 1, 2005.

Debt

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to own all of the voting stock of Pepco, DPL and ACE. The agreement does not include any ratings triggers.

Effective Tax Rate

Pepco's effective tax rate for the three months ended June 30, 2005 was 42% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit) and the flow-through of certain book tax depreciation differences, partially offset by the flow-through of deferred investment tax credits and certain removal costs.

Pepco's effective tax rate for the three months ended June 30, 2004 was 41% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit) and the flow-through of certain book tax depreciation differences, partially offset by the flow-through of deferred investment tax credits and certain removal costs.

Pepco's effective tax rate for the six months ended June 30, 2005 was 43% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit) and changes in estimates related to tax liabilities of prior years subject to audit, partially offset by the flow-through of deferred investment tax credits and certain removal costs.

Pepco's effective tax rate for the six months ended June 30, 2004 was 40% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit, including the benefit associated with the retroactive adjustment for the issuance of final consolidated return regulations by a local taxing authority, which is the primary reason for the lower effective rate as compared to 2005) and the flow-through of certain book tax depreciation differences, partially offset by the flow-through of deferred investment tax credits and certain removal costs.

Related Party Transactions

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including Pepco, pursuant to a service agreement. 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 in consolidation and no profit results from these transactions. PHI Service Company costs directly charged or allocated to Pepco for the three and six months ended June 30, 2005 and 2004 were approximately $27.3 million and $20.6 million and $53.5 million and $44.5 million, respectively.

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Certain subsidiaries of Pepco Energy Services perform utility maintenance services, including services that are treated as capital costs, for Pepco. Amounts paid by Pepco to these companies for the three and six months ended June 30, 2005 and 2004 were approximately $2.4 million and $3.8 million and $4.9 million and $7.3 million, respectively.

As of June 30, 2005 and December 31, 2004, Pepco had the following balances on its Balance Sheets due to and from related parties:

		2005			2004
		(In Millions)
Payable to Related Party (current)
PHI Service Company	$	(12.9	)	$	(12.9	)
Pepco Energy Services (a)		(32.4	)		(12.5	)
Other Related Party Activity		-			(.1	)
Total Payable to Related Parties	$	(45.3	)	$	(25.5	)
Money Pool Balance with Pepco Holdings (included in cash and cash equivalents in 2005 and in short-term debt in 2004 on the balance sheet)		47.9			(14.0	)

(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.

New Accounting Standards

SFAS No. 154

In May 2005, the Financial Accounting Standards Board (FASB) issued Statement No. 154, "Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3" (SFAS No. 154).SFAS No. 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. The reporting of a correction of an error by restating previously issued financial statements is also addressed by SFAS No. 154. This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Early adoption is permitted.

FIN 47

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(3) 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.

(4) COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Relationship with Mirant Corporation

In 2000, Pepco sold substantially all of its electricity generation assets to Mirant Corporation, formerly Southern Energy, Inc. As part of the Asset Purchase and Sale Agreement, Pepco entered into several ongoing contractual arrangements with Mirant Corporation and certain of its subsidiaries (collectively, Mirant). On July 14, 2003, Mirant Corporation and most of its subsidiaries filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas (the Bankruptcy Court).

Transition Power Agreements

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Mirant entities with the Bankruptcy Court, certain Mirant entities other than Mirant Corporation would pay significantly higher percentages of the claims of their creditors than would Mirant Corporation. The amount that Pepco will be able to recover from the Mirant bankruptcy estate with respect to the Pepco TPA Claim will depend on the amount of assets available for distribution to creditors of the Mirant entities that are found to be liable for the Pepco TPA Claim.

Power Purchase Agreements

Under agreements with FirstEnergy Corp., formerly Ohio Edison (FirstEnergy), and Allegheny Energy, Inc., both entered into in 1987, Pepco is obligated to purchase from FirstEnergy 450 megawatts of capacity and energy annually through December 2005 (the FirstEnergy PPA). Under the Panda PPA, entered into in 1991, Pepco is obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021. In each case, the purchase price is substantially in excess of current market price. As a part of the Asset Purchase and Sale Agreement, Pepco entered into a "back-to-back" arrangement with Mirant. Under this arrangement, Mirant is obligated, among other things, to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the FirstEnergy PPA and the Panda PPA at a price equal to the price Pepco is obligated to pay under the FirstEnergy PPA and the Panda PPA (the PPA-Related Obligations).

Pepco Pre-Petition Claims

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Mirant's Attempt to Reject the PPA-Related Obligations

On December 9, 2004, the District Court issued an order again denying Mirant's motion to reject the PPA-Related Obligations. The District Court found that the PPA-Related Obligations are not severable from the Asset Purchase and Sale Agreement and that the Asset Purchase and Sale Agreement cannot be rejected in part, as Mirant was seeking to do. On December 16, 2004, the Creditors' Committee appealed the District Court's order to the Court of Appeals, and on December 20, 2004, Mirant also appealed the District Court's order. Mirant and the Creditors' Committee each filed its brief on April 4, 2005. Pepco's and FERC's briefs were filed in May 2005. Oral arguments have not yet been scheduled.

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Any repayment by Pepco of amounts paid by Mirant would entitle Pepco to file a claim against the bankruptcy estate in an amount equal to the amount repaid. Pepco believes that, to the extent such amounts were not recovered from the Mirant bankruptcy estate; they would be recoverable as stranded costs from customers through distribution rates as described below.

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Mirant's Fraudulent Transfer Claim

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other professionals. Moreover, the asset sale was approved by FERC and was reviewed by the MPSC and the DCPSC. Accordingly, Pepco believes Mirant's complaint is entirely without merit and is vigorously contesting the claim.

The SMECO Agreement

On March 15, 2004, Mirant filed a complaint with the Bankruptcy Court seeking a declaratory judgment that the SMECO Agreement is an unexpired lease of non-residential real property rather than an executory contract and that if Mirant were to successfully reject the agreement, any claim against the bankruptcy estate for damages made by SMECO (or by Pepco as subrogee) would be subject to the provisions of the Bankruptcy Code that limit the recovery of rejection damages by lessors. Pepco believes that there is no reasonable factual or legal basis to support Mirant's contention that the SMECO Agreement is a lease of real property. Litigation continues and the outcome of this proceeding cannot be predicted.

Mirant Plan of Reorganization

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Pepco disagrees. Pepco filed a motion for rehearing on July 18, 2005. Pepco cannot predict the outcome of its motion for rehearing.

Divestiture Cases

District of Columbia

Pepco believes that a sharing of EDIT and ADITC would violate the normalization rules. 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. Pepco, in addition to sharing with customers the generation-related EDIT and ADITC balances, would have to pay to the IRS an amount equal to Pepco's $5.8 million District of Columbia jurisdictional generation-related ADITC balance as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance 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. As of June 30, 2005, the District of Columbia jurisdictional transmission and distribution related ADITC balance was approximately $5.7 million.

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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 condition. It is uncertain when the DCPSC will issue a decision.

Maryland

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decision is rendered and could have a material adverse effect on 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 condition.

SOS Proceedings

District of Columbia

For a history of Pepco's SOS proceeding before the DCPSC, please refer to Note (11) Commitments and Contingencies, to the Consolidated Financial Statements of Pepco included in Pepco's Annual Report on Form 10-K for the year ended December 31, 2004. The TPA with Mirant under which Pepco obtained the fixed-rate District of Columbia SOS supply ended on January 22, 2005, while the new SOS supply contracts with the winning bidders in the competitive procurement process began on February 1, 2005. Pepco procured power separately on the market for next-day deliveries to cover the period from January 23 through January 31, 2005, before the new District of Columbia SOS contracts began. Consequently, Pepco had to pay the difference between the procurement cost of power on the market for next-day deliveries and the current District of Columbia SOS rates charged to customers during the period from January 23 through January 31, 2005. In addition, because the new District of Colu mbia SOS rates did not go into effect until February 8, 2005, Pepco had to pay the difference between the procurement cost of power under the new District of Columbia SOS contracts and the District of Columbia SOS rates charged to customers for the period from February 1 to February 7, 2005. The total amount of the difference is estimated to be approximately $8.7 million. This difference, however, was included in the calculation of the Generation Procurement Credit (GPC) for the District of Columbia for the period February 8, 2004 through February 7, 2005. The GPC provides for a sharing between Pepco's customers and shareholders, on an annual basis, of any margins, but not losses, that Pepco earned providing SOS in the District of Columbia during the four-year period from February 8, 2001 through February 7, 2005. Currently, based on the rates paid by Pepco to Mirant under the TPA Settlement, there is no customer sharing. However, in the event that Pepco were to ultimately realize a significant rec overy from the Mirant bankruptcy estate associated with the TPA Settlement, the GPC would be recalculated, and the amount of customer sharing with respect to such recovery would be reduced because of the $8.7 million loss being included in the GPC calculation.

General Litigation

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,

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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. Of the approximately 250 remaining asbestos cases pending against Pepco, approximately 85 cases were filed after December 19, 2000, and have been tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement.

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.

In October 1995, Pepco received notice from the Environmental Protection Agency (EPA) that it, along with several hundred other companies, might be a potentially responsible party (PRP) in connection with the Spectron Superfund Site in Elkton, Maryland. The site was operated as a hazardous waste disposal, recycling and processing facility from 1961 to 1988.

In the early 1970s, Pepco sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a nonaffiliated company. In December 1987, Pepco was notified by EPA that it, along with a number of other utilities and non-utilities, was a PRP in connection with the PCB contamination at the site.

In October 1994, a Remedial Investigation/Feasibility Study including a number of possible remedies was submitted to the EPA. In December 1997, the EPA issued a Record of Decision that set forth a selected remedial action plan with estimated implementation costs of

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approximately $17 million. In June 1998, the EPA issued a unilateral administrative order to Pepco and 12 other PRPs to conduct the design and actions called for in its decision. In May 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. In October 2003, the bankruptcy court confirmed a reorganization plan that incorporates the terms of a settlement among the debtors, the United States and a group of utility PRPs including Pepco. Under the settlement, the reorganized entity/site owner will pay a total of $13.25 million to remediate the site.

As of May 1, 2005, Pepco had accrued $1.7 million to meet its liability for a remedy at the Metal Bank/Cottman Avenue site. At the present time, it is not possible to estimate the total extent of EPA's administrative and oversight costs or the expense associated with a site remedy ultimately implemented. However, Pepco believes that its liability at this site will not have a material adverse effect on its financial condition or results of operations.

(5)SUBSEQUENT EVENTS

Sale of Buzzard Point Property

IRS Revenue Ruling

During 2001, Pepco changed its methods of accounting with respect to capitalizable construction costs for income tax purposes, which allow Pepco to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through June 30, 2005, these accelerated deductions have generated approximately $119 million in tax cash flow benefits, primarily attributable to its 2001 tax returns. On August 2, 2005, the IRS issued Revenue Ruling 2005-53 (the Ruling) that will limit the ability of Pepco to utilize this method of accounting. Under the Ruling, Pepco may have to recapitalize and depreciate a portion of these expenses and repay a portion of the past income tax benefits, along with interest thereon.

Pepco believes that its tax position was appropriate based on applicable statutes, regulations, and case law in effect at the time the companies made the change in accounting method for income tax purposes. However, there is no assurance that Pepco's position will prevail.

The tax benefits derived from the change in accounting method have been accounted for as temporary differences in determining Pepco's deferred income tax balances for financial reporting purposes. Consequently, the repayment of the tax benefits, if required, would affect cash flows and deferred income tax balances, but would not affect earnings, other than a charge for the accrual of related interest.

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DELMARVA POWER & LIGHT COMPANY STATEMENTS OF EARNINGS (Unaudited)
	Three Months Ended June 30,						Six Months Ended June 30,
		2005			2004			2005			2004
		(Millions of Dollars)

Operating Revenues
Electric	$	241.4		$	248.3		$	500.0		$	499.1
Natural Gas		47.5			49.3			159.2			149.2
Total Operating Revenues		288.9			297.6			659.2			648.3

Operating Expenses
Fuel and purchased energy		155.9			161.7			318.1			319.5
Gas purchased		35.8			37.7			120.9			111.4
Other operation and maintenance		42.4			38.2			84.8			84.3
Depreciation and amortization		18.4			18.2			37.4			36.3
Other taxes		8.1			.5			17.5			9.5
Gain on sale of assets		(.9	)		-			(.9	)		-
Total Operating Expenses		259.7			256.3			577.8			561.0

Operating Income		29.2			41.3			81.4			87.3

Other Income (Expenses)
Interest and dividend income		.3			-			.5			.1
Interest expense		(9.2	)		(8.0	)		(17.8	)		(17.0	)
Other income		2.2			1.7			2.7			2.7
Other expenses		(1.1	)		(1.1	)		(1.1	)		(1.1	)
Total Other Expenses, Net		(7.8	)		(7.4	)		(15.7	)		(15.3	)

Income Before Income Tax Expense		21.4			33.9			65.7			72.0

Income Tax Expense		8.9			14.0			29.4			29.7

Net Income		12.5			19.9			36.3			42.3

Dividends on Redeemable Serial Preferred Stock		.2			.3			.5			.5

Earnings Available for Common Stock		12.3			19.6			35.8			41.8

Retained Earnings at Beginning of Period		363.8			367.5			364.7			367.4

Dividends paid to Pepco Holdings		(12.0	)		(22.4	)		(36.4	)		(44.5	)

Retained Earnings at End of Period	$	364.1		$	364.7		$	364.1		$	364.7

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

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DELMARVA POWER & LIGHT COMPANY BALANCE SHEETS (Unaudited)
	June 30,			December 31,
ASSETS		2005			2004
	(Millions of Dollars)

CURRENT ASSETS
Cash and cash equivalents	$	4.3		$	3.7
Restricted cash		-			4.8
Accounts receivable, less allowance for uncollectible accounts of $9.4 million and $8.7 million, respectively		176.9			174.7
Fuel, materials and supplies-at average cost		28.5			38.4
Prepaid expenses and other		11.6			11.6
Total Current Assets		221.3			233.2

INVESTMENTS AND OTHER ASSETS
Goodwill		48.5			48.5
Regulatory assets		122.5			140.3
Prepaid pension expense		209.0			204.7
Other		28.7			29.8
Total Investments and Other Assets		408.7			423.3

PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,356.2			2,303.4
Accumulated depreciation		(781.0	)		(755.0	)
Net Property, Plant and Equipment		1,575.2			1,548.4

TOTAL ASSETS	$	2,205.2		$	2,204.9

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

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DELMARVA POWER & LIGHT COMPANY BALANCE SHEETS (Unaudited)
		June 30,			December 31,
LIABILITIES AND SHAREHOLDER'S EQUITY			2005			2004
	(Millions of dollars, except shares)

CURRENT LIABILITIES
Short-term debt		$	140.6		$	137.0
Accounts payable and accrued liabilities			51.9			59.7
Accounts payable due to associated companies			53.3			46.3
Capital lease obligations due within one year			.2			.2
Taxes accrued			23.3			6.6
Interest accrued			6.2			6.3
Other			44.8			60.9
Total Current Liabilities			320.3			317.0

DEFERRED CREDITS
Regulatory liabilities			226.9			220.6
Income taxes			432.8			430.9
Investment tax credits			11.2			11.7
Above-market purchased energy contracts and other electric restructuring liabilities			27.1			30.6
Other			29.3			32.5
Total Deferred Credits			727.3			726.3

LONG-TERM LIABILITIES
Long-term debt			536.3			539.6
Capital lease obligations			.1			.2
Total Long-Term Liabilities			536.4			539.8

COMMITMENTS AND CONTINGENCIES (NOTE 4)

REDEEMABLE SERIAL PREFERRED STOCK			21.7			21.7

SHAREHOLDER'S EQUITY
Common stock, $2.25 par value, authorized 1,000,000 shares, issued 1,000 shares			-			-
Premium on stock and other capital contributions			245.4			245.4
Capital stock expense			(10.0	)		(10.0	)
Retained earnings			364.1			364.7
Total Shareholder's Equity			599.5			600.1

TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY		$	2,205.2		$	2,204.9

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

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DELMARVA POWER & LIGHT COMPANY STATEMENTS OF CASH FLOWS (Unaudited)
		Six Months Ended June 30,
			2005			2004
	(Millions of Dollars)
OPERATING ACTIVITIES
Net income		$	36.3		$	42.3
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization			37.4			36.3
Gain on sale of assets			(.9	)		-
Deferred income taxes			(2.8	)		5.0
Investment tax credit adjustments			(.5	)		(.5	)
Regulatory assets, net			25.5			4.9
Changes in:
Accounts receivable			(2.2	)		(.9	)
Accounts payable and accrued liabilities			(10.0	)		.7
Interest and taxes accrued			12.8			24.6
Other changes in working capital			9.9			9.9
Net other operating			(9.7	)		1.6
Net Cash From Operating Activities			95.8			123.9

INVESTING ACTIVITIES
Net investment in property, plant and equipment			(64.0	)		(56.8	)
Proceeds from sale of property			1.2			-
Net other investing activities			4.8			(3.9	)
Net Cash Used By Investing Activities			(58.0	)		(60.7	)

FINANCING ACTIVITIES
Dividends paid to Pepco Holdings			(36.4	)		(44.5	)
Dividends paid on preferred stock			(.5	)		(.5	)
Issuances of long-term debt			100.0			-
Reacquisition of long term debt			(102.7	)		(2.5	)
Redemption of debentures issued to financing trust			-			(70.0	)
Net change in short-term debt			3.4			53.7
Net other financing activities			(1.0	)		(.1	)
Net Cash Used By Financing Activities			(37.2	)		(63.9	)

Net Increase (Decrease) in Cash and Cash Equivalents			.6			(.7	)
Cash and Cash Equivalents at Beginning of Period			3.7			4.9

CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	4.3		$	4.2

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

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NOTES TO UNAUDITED 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 Virginia 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 varies by jurisdiction as follows:

	Delaware	Provider of Last Resort service (POLR) -- before May 1, 2006 Standard Offer Service (SOS) -- on and after May 1, 2006
	Maryland	Standard Offer Service
	Virginia	Default Service

DPL also refers to this supply service in each of its jurisdictions generally as Default Electricity Supply.

DPL's electricity distribution service territory covers approximately 6,000 square miles and has a population of approximately 1.28 million. DPL's natural gas distribution service territory covers approximately 275 square miles and has a population of approximately 523,000. DPL is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI). Because PHI is a public utility holding company registered under the Public Utility Holding Company Act of 1935 (PUHCA), the relationship between PHI and DPL and certain activities of DPL are subject to the regulatory oversight of the Securities and Exchange Commission (SEC) under PUHCA.

(2) ACCOUNTING POLICY, PRONOUNCEMENTS, AND OTHER DISCLOSURES

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 SEC, 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, 2004. In the opinion of DPL's management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to fairly state DPL's financial condition as of June 30, 2005, its results of operations for the three and six months ended June 30, 2005, and its cash flows for the six months ended June 30, 2005 in accordance with GAAP. Interim results for the three and six months ended June 30, 2005 may not be indicative of results that will be realized for the full year ending December 31, 2005 since the sales of electric energy are seasonal. Additionally, certain prior period balances have been reclassified in order to conform to current period presentation.

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FIN 45

As of June 30, 2005, DPL did not have material obligations under guarantees or indemnifications issued or modified after December 31, 2002, which are required to be recognized as liabilities on its consolidated balance sheets.

Components of Net Periodic Benefit Cost/(Income)

The following Pepco Holdings' information is for the three months ended June 30, 2005 and 2004.

		Pension Benefits						Other Post-Retirement Benefits
		2005			2004			2005			2004
	(In Millions)
Service cost	$	9.6		$	8.4		$	2.1		$	2.4
Interest cost		23.6			23.5			8.4			8.3
Expected return on plan assets		(32.1	)		(32.3	)		(2.9	)		(2.8	)
Amortization of prior service cost		.3			.3			(.9	)		-
Amortization of net loss		2.7			(1.3	)		3.4			3.1
Net periodic benefit cost/(income)	$	4.1		$	(1.4	)	$	10.1		$	11.0

The following Pepco Holdings' information is for the six months ended June 30, 2005 and 2004.

		Pension Benefits						Other Post-Retirement Benefits
		2005			2004			2005			2004
	(In Millions)
Service cost	$	19.0		$	18.0		$	4.2		$	4.8
Interest cost		47.9			47.3			16.8			16.7
Expected return on plan assets		(62.8	)		(62.1	)		(5.4	)		(5.7	)
Amortization of prior service cost		.6			.5			(1.9	)		-
Amortization of net loss		5.2			3.3			5.9			6.2
Net periodic benefit cost	$	9.9		$	7.0		$	19.6		$	22.0

Pension

The 2005 pension net periodic benefit cost/(income) for the three months ended June 30, of $4.1 million includes $(2.6) million for DPL. The 2005 pension net periodic benefit cost/(income) for the six months ended June 30, of $9.9 million includes $(3.9) million for DPL. The remaining pension net periodic benefit cost is for other PHI subsidiaries. The 2004 pension net periodic benefit cost/(income) for the three months ended June 30, of $(1.4) million includes $(3.9) million for DPL. The 2004 pension net periodic benefit cost/(income) for the six months ended June 30, of $7.0 million includes $(4.4) million for DPL. The remaining pension net periodic benefit cost is for other PHI subsidiaries.

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The six months ended June 30, 2005 pension net periodic benefit cost reflects a reduction in the expected return on assets assumption from 8.75% to 8.50% effective January 1, 2005.

Pension Contributions

Other Post-Retirement Benefits

The 2005 other post-retirement net periodic benefit cost for the three months ended June 30, of $10.1 million includes $.5 million for DPL. The 2005 other post-retirement net periodic benefit cost for the six months ended June 30, of $19.6 million includes $3.0 million for DPL. The remaining other post-retirement net periodic benefit cost is for other PHI subsidiaries. The 2004 other post-retirement net periodic benefit cost for the three months ended June 30, of $11.0 million includes $2.3 million for DPL. The 2004 other post-retirement net periodic benefit cost for the six months ended June 30, of $22.0 million includes $4.7 million for DPL. The remaining other post-retirement net periodic benefit cost is for other PHI subsidiaries.

The six months ended June 30, 2005 other post-retirement net periodic benefit cost reflects a reduction in the expected return on assets assumption from 8.75% to 8.50% effective January 1, 2005.

Debt

The credit agreement 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

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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 made by the borrower at the time the credit agreement was entered into also must be true at the time the facility is utilized, and the borrower must be in compliance with specified covenants, including the financial covenant described below. However, a material adverse change in the borrower's business, property, or financial condition subsequent to the entry into the credit agreement is not a condition to the availability of credit under the facility. Among the covenants contained in the credit agreement are (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, (ii) a restriction on sales or other dispositions of assets, other than sales and dispositions permitted by the credit agreement and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than liens permitted by the credit agreement. The failure to satisfy any of the covenants or the occurrence of specified events that constitute events of default that could result in the acceleration of repayment obligations of the borrower. The events of default include (i) the failure of any borrowing company or any of its significant subsidiaries to pay when due, or the acceleration of, certain indebtedness under other borrowing arrangements, (ii) certain bankruptcy events, judgments or decrees against any borrowing company or its significant subsidiaries, and (iii) a change in control (as defined in the credit agreement) of Pepco Holdings or the failure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE. The agreement does not include any ratings triggers.

In June 2005, DPL issued $100 million of 5.0% unsecured notes due 2015. The net proceeds were used to redeem $100 million of DPL's 7.71% first mortgage bonds due 2025.

In June 2005, DPL made a sinking fund payment of $2.7 million on its 6.95% first mortgage bonds due 2008.

Effective Tax Rate

DPL's effective tax rate for the three months ended June 30, 2005 was 42%as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit) and the flow-through of certain book tax depreciation differences partially offset by the flow-through of deferred investment tax credits.

DPL's effective tax rate for the three months ended June 30, 2004 was 41% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit) and the flow-through of certain book tax depreciation differences partially offset by the flow-through of deferred investment tax credits.

DPL's effective tax rate for the six months ended June 30, 2005 was 45% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit) changes in estimates related to tax liabilities of prior tax years subject to audit and the flow-through of certain book tax depreciation differences partially offset by the flow-through of deferred investment tax credits.

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DPL's effective tax rate for the six months ended June 30, 2004 was 41% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit) and the flow-through of certain book tax depreciation differences partially offset by the flow-through of deferred investment tax credits.

Related Party Transactions

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including DPL, pursuant to a service agreement. 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 in consolidation and no profit results from these transactions. PHI Service Company costs directly charged or allocated to DPL for the three and six months ended June 30, 2005 and 2004 were $24.7 million and $23.5 million and $49.2 million and $49.3 million, respectively.

In addition to the PHI Service Company charges described above, DPL's Statements of Earnings include the following expenses incurred by DPL in related party transactions:

	For the Quarters Ended June 30,				For the Six Months Ended June 30,
		2005		2004		2005		2004
	(In Millions)
Full Requirements Contract with Conectiv Energy Supply for power, capacity and ancillary services to service POLR (included in Fuel and purchased energy)	$	100.2	$	142.7	$	195.3	$	290.7
SOS agreement with Conectiv Energy Supply (included in Fuel and purchased energy)		11.2		-		22.2		-

As of June 30, 2005 and December 31, 2004, DPL had the following balances on its Balance Sheets due to and from related parties:

		2005			2004
		(In Millions)
Receivable from Related Party
King Street Assurance	$	6.7		$	6.7
ACE		.3			-
Payable to Related Party (current)
PHI Service Company		(8.8	)		(12.6	)
Conectiv Energy Supply		(51.9	)		(38.5	)
Delmarva Operating Service Company		-			(2.4	)
Other Related Party Activity		.4			.5
Total Payable to Related Parties	$	(53.3	)	$	(46.3	)
Money Pool Balance with Pepco Holdings (included in short-term debt on the balance sheet)		(32.8	)		(29.5	)

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New Accounting Standards

SFAS No. 154

FIN 47

(3) 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.

(4) COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Rate Proceedings

Delaware

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Pursuant to the April 16, 2002 merger settlement agreement in Delaware, on May 4, 2005, DPL made a filing with the DPSC whereby DPL seeks approval of a proposed increase of approximately $6.2 million in electric transmission service revenues, or about 1.1% of total Delaware retail electric revenues. This proposed revenue increase is the Delaware retail portion of the increase in the "Delmarva zonal" transmission rates on file with the Federal Energy Regulatory Commission (FERC) under the Open Access Transmission Tariff (OATT) of the PJM Interconnection, LLC (PJM). This level of revenue increase will decrease to the extent that competitive retail suppliers provide a supply and transmission service to retail customers. In that circumstance, PJM would charge the competitive retail supplier the PJM OATT rate for transmission service into the Delmarva zone and DPL's charges to the retail customer would exclude as a "shopping credit" an amount equal to the SOS supply charge and the transmission and ancillary charges that would otherwise be charged by DPL to the retail customer. DPL began collecting this rate change for service rendered on and after June 3, 2005, subject to refund.

Default Service Proceedings

Virginia

Under amendments to the Virginia Electric Utility Restructuring Act implemented in March 2004, DPL is obligated to offer Default Service to customers in Virginia for an indefinite period until relieved of that obligation by the Virginia State Corporation Commission (VSCC). DPL currently obtains all of the energy and capacity needed to fulfill its Default Service obligations in Virginia under a supply agreement with Conectiv Energy that commenced on January 1, 2005 and expires in May 2006 (the 2005 Supply Agreement). A prior agreement, also with Conectiv Energy, terminated effective December 31, 2004. DPL entered into the 2005 Supply Agreement after conducting a competitive bid procedure in which Conectiv Energy was the lowest bidder.

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proceeding addressing "Proposed Rules Governing Exemptions to Minimum Stay Requirements and Wires Charges," the VSCC staff recognized that DPL should be entitled to earn a reasonable margin related to hourly pricing customers. DPL continues to maintain that a margin should be earned on all customer classes. DPL cannot predict the outcome of this proceeding.

Delaware

Under a settlement approved by the DPSC, DPL is required to provide POLR service to retail customers in Delaware until May 1, 2006. In October 2004, the DPSC initiated a proceeding to investigate and determine which entity should act as the SOS supplier in DPL's Delaware service territory after May 1, 2006, and what prices should be charged for SOS after May 1, 2006. The process used in Delaware consists of three separate stages. The Stage 1 process was constructed to allow the DPSC to determine by February 28, 2005 the fundamental issues related to the selection of an SOS supplier. Stage 2 would resolve issues relating to the process under which supply would be acquired by the SOS provider and the way in which SOS prices would be set and monitored. In Stage 3, these selection and pricing mechanisms would be implemented to determine the post-May 2006 SOS supplier and the post-May 2006 SOS price. On January 26, 2005, the DPSC staff issued a report recommending to the DPSC that DPL be selected as the SOS supplier, subject to further discussions as to how to establish SOS prices. On March 22, 2005, the DPSC issued an order approving DPL as the SOS provider at market rates after May 1, 2006, when DPL's current fixed rate POLR obligation ends. The DPSC also approved a structure whereby DPL will retain the SOS obligation for an indefinite period until changed by the DPSC, and will purchase the power supply required to satisfy its market rate SOS obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure. The DPSC will determine in the future the duration of DPL's market-rate SOS obligation and the margin, if any, that DPL will be permitted to earn in conjunction with providing, and other terms and conditions regarding, SOS.

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as an option for General Service - Primary voltage (GS-P) customers. If approved, a competitive bid process will be used to procure the full requirements of customers eligible for a fixed-price SOS. In addition to the costs of capacity, energy, transmission, and ancillary services associated with the fixed-price SOS and HPS, DPL's initial rates would include a component referred to as the Reasonable Allowance for Retail Margin (RARM). Components of the RARM would include estimated incremental expenses, a $2.75 million return, a cash working capital allowance, and recovery with a return over 5 years of the capitalized costs of a billing system to be used for billing HPS customers. The $2.75 million return would be recovered through a 0.6 mill charge per kwh to the fixed-price SOS customers and flat, non-bypassable charges of $400 per month for GS-T customers and $150 per month for GS-P customers who elected the HPS form of SOS. All such costs are presumed by DPL to be recoverable, but are subject to a udit; furthermore, no settlement can override the statutory requirement that costs not be the product of waste, bad faith or an abuse of discretion. The settlement proposes that there will be a true-up proceeding during the second year to establish SOS and HPS rates based on the year-one actual costs, quantities of SOS and HPS provided, and the amount of actual recovery on the $2.75 million return. After year two, the only elements of rates that would be trued-up are the differences between the billed retail rates and the costs paid to the winning bidders in competitive SOS proceedings. Parties, including DPL, would be permitted to initiate a proceeding with the DPSC to adjust rates prospectively to reflect changes in incremental costs or quantities sold.

In testimony filed on July 29, 2005, the settlement was contested by the intervenors in the case that did not sign the settlement agreement. A public hearing was held on August 1 and a formal evidentiary hearing before a Hearing Examiner was held on August 4, 2005. The procedural schedule currently provides for DPSC deliberations by late September 2005, with a written order in October. Potential modifications to the settlement are also being discussed with the contesting parties. DPL cannot predict the outcome of this proceeding.

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.

In July 2004, DPL entered into an Administrative Consent Order with the Maryland Department of the Environment (MDE) to perform a Remedial Investigation/Feasibility Study

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(RI/FS) to further identify the extent of soil, sediment and ground and surface water contamination related to former manufactured gas plant (MGP) operations at the Cambridge, Maryland site on DPL-owned property and to investigate the extent of MGP contamination on adjacent property. The costs for completing the RI/FS for this site are approximately $300,000, approximately $50,000 of which will be expended in 2005. The costs of cleanup resulting from the RI/FS will not be determinable until the RI/FS is completed and an agreement with respect to cleanup is reached with the MDE. Due to project delays, DPL now expects that the completion date for the RI/FS will be in the fourth quarter of 2005.

In October 1995, DPL received notice from the Environmental Protection Agency (EPA) that it, along with several hundred other companies, might be a potentially responsible party (PRP) in connection with the Spectron Superfund Site in Elkton, Maryland. The site was operated as a hazardous waste disposal, recycling and processing facility from 1961 to 1988. In April 1996 DPL, with numerous other PRPs, entered into an administrative order of consent with EPA to perform an RI/FS at the site. In February 2003, the EPA informed DPL that it will have no future liability for contribution to the remediation of the site.

In the early 1970s, DPL sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a nonaffiliated company. In December 1987, DPL was notified by EPA that it, along with a number of other utilities and non-utilities, was a PRP in connection with the PCB contamination at the site.

In October 1994, an RI/FS including a number of possible remedies was submitted to the EPA. In December 1997, the EPA issued a Record of Decision that set forth a selected remedial action plan with estimated implementation costs of approximately $17 million. In 1999, DPL entered into a de minimis settlement with EPA and paid approximately $107,000 to resolve its liability for cleanup costs at the Metal Bank/Cottman Avenue site. The de minimis settlement did not resolve DPL's responsibility for natural resource damages, if any, at the site. DPL believes that any liability for natural resource damages at this site will not have a material adverse effect on its financial condition or results of operations.

(5) CHANGES IN ACCOUNTING ESTIMATES

During the second quarter of 2005, DPL recorded the impact of a reduction in estimated unbilled revenue, primarily reflecting an increase in the estimated amount of power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). These changes in accounting estimates reduced second quarter earnings by approximately $1.0 million.

(6) SUBSEQUENT EVENT

IRS Revenue Ruling

During 2001, DPL changed its methods of accounting with respect to capitalizable construction costs for income tax purposes, which allow DPL to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through June 30, 2005, these accelerated deductions have generated approximately $91 million in tax cash flow benefits, primarily attributable to its 2001 tax returns. On August 2, 2005, the IRS issued Revenue Ruling 2005-53 (the Ruling) that will limit the ability of DPL to utilize this method of

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accounting. Under the Ruling, DPL may have to recapitalize and depreciate a portion of these expenses and repay a portion of the past income tax benefits, along with interest thereon.

DPL believes that its tax position was appropriate based on applicable statutes, regulations, and case law in effect at the time the companies made the change in accounting method for income tax purposes. However, there is no assurance that DPL's position will prevail.

The tax benefits derived from the change in accounting method have been accounted for as temporary differences in determining DPL's deferred income tax balances for financial reporting purposes. Consequently, the repayment of the tax benefits, if required, would affect cash flows and deferred income tax balances, but would not affect earnings, other than a charge for the accrual of related interest.

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF EARNINGS (Unaudited)
	Three Months Ended June 30,						Six Months Ended June 30,
		2005			2004			2005			2004
		(Millions of Dollars)

Operating Revenues	$	290.7		$	315.9		$	600.0		$	638.3

Operating Expenses
Fuel and purchased energy		199.0			193.6			387.1			387.2
Other operation and maintenance		45.1			46.2			92.4			98.0
Depreciation and amortization		27.0			32.5			56.9			66.5
Other taxes		5.0			5.3			10.2			9.2
Deferred electric service costs		(18.3	)		(6.0	)		.8			9.0
Gain on sale of asset		-			(14.4	)		-			(14.4	)
Total Operating Expenses		257.8			257.2			547.4			555.5

Operating Income		32.9			58.7			52.6			82.8

Other Income (Expenses)
Interest and dividend income		.8			.6			1.5			1.1
Interest expense		(14.5	)		(15.8	)		(28.6	)		(31.3	)
Other income		1.8			1.3			3.5			3.7
Total Other Expenses, Net		(11.9	)		(13.9	)		(23.6	)		(26.5	)

Income Before Income Tax Expense		21.0			44.8			29.0			56.3

Income Tax Expense		8.4			18.4			11.4			23.2

Income Before Extraordinary Item		12.6			26.4			17.6			33.1

Extraordinary Item (net of tax of $6.2 million)		-			-			9.0			-

Net Income		12.6			26.4			26.6			33.1

Dividends on Redeemable Serial Preferred Stock		.1			.1			.1			.1

Earnings Available for Common Stock		12.5			26.3			26.5			33.0

Retained Earnings at Beginning of Period		219.9			160.6			213.3			159.6

Dividends paid to Pepco Holdings		(40.5	)		-			(47.9	)		(5.7	)

Retained Earnings at End of Period	$	191.9		$	186.9		$	191.9		$	186.9

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

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)
		June 30,			December 31,
ASSETS			2005			2004
	(Millions of Dollars)

CURRENT ASSETS
Cash and cash equivalents		$	4.2		$	4.2
Restricted cash			9.2			13.7
Accounts receivable, less allowance for uncollectible accounts of $4.5 million and $4.5 million, respectively			196.4			176.4
Fuel, materials and supplies-at average cost			39.9			38.1
Prepaid expenses and other			47.3			4.9
Total Current Assets			297.0			237.3

INVESTMENTS AND OTHER ASSETS
Regulatory assets			1,035.7			1,069.4
Restricted funds held by trustee			9.4			9.1
Other			23.7			24.1
Total Investments and Other Assets			1,068.8			1,102.6

PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			1,869.8			1,819.1
Accumulated depreciation			(565.0	)		(680.0	)
Net Property, Plant and Equipment			1,304.8			1,139.1

TOTAL ASSETS		$	2,670.6		$	2,479.0

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

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)
		June 30,			December 31,
LIABILITIES AND SHAREHOLDER'S EQUITY			2005			2004
	(Millions of dollars, except shares)

CURRENT LIABILITIES
Short-term debt		$	261.0		$	123.4
Accounts payable and accrued liabilities			113.2			85.0
Accounts payable to associated companies			17.0			12.4
Taxes accrued			32.2			21.3
Interest accrued			13.8			14.3
Other			34.2			35.6
Total Current Liabilities			471.4			292.0

DEFERRED CREDITS
Regulatory liabilities			173.4			44.6
Income taxes			492.6			496.0
Investment tax credits			18.7			19.7
Pension benefit obligation			48.0			44.0
Other post-retirement benefit obligation			44.4			44.7
Other			18.6			34.4
Total Deferred Credits			795.7			683.4

LONG-TERM LIABILITIES
Long-term debt			376.7			441.6
Transition Bonds issued by ACE Funding			509.5			523.3
Capital lease obligations			.2			.2
Total Long-Term Liabilities			886.4			965.1

COMMITMENTS AND CONTINGENCIES (NOTE 4)

REDEEMABLE SERIAL PREFERRED STOCK			6.2			6.2

SHAREHOLDER'S EQUITY
Common stock, $3.00 par value, authorized 25,000,000 shares, and 8,546,017 shares outstanding			25.6			25.6
Premium on stock and other capital contributions			294.0			294.0
Capital stock expense			(.6	)		(.6	)
Retained earnings			191.9			213.3
Total Shareholder's Equity			510.9			532.3

TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY		$	2,670.6		$	2,479.0

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

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
		Six Months Ended June 30,
			2005			2004
	(Millions of Dollars)
OPERATING ACTIVITIES
Net income		$	26.6		$	33.1
Adjustments to reconcile net income to net cash from operating activities:
Extraordinary item			(15.2	)		-
Gain on sale of asset			-			(14.4	)
Depreciation and amortization			56.9			66.5
Deferred income taxes			(2.7	)		(4.8	)
Regulatory assets, net			1.7			6.5
Changes in:
Accounts receivable			(20.0	)		(27.5	)
Accounts payable and accrued liabilities			29.2			13.9
Prepaid New Jersey sales and excise tax			(43.6	)		(39.3	)
Other changes in working capital			8.4			.7
Net other operating			5.0			(.9	)
Net Cash From Operating Activities			46.3			33.8

INVESTING ACTIVITIES
Net investment in property, plant and equipment			(61.8	)		(69.2	)
Net other investing activities			4.7			(6.2	)
Net Cash Used By Investing Activities			(57.1	)		(75.4	)

FINANCING ACTIVITIES
Common stock repurchase			-			(67.5	)
Dividends paid to Pepco Holdings			(47.9	)		(5.7	)
Dividends paid on preferred stock			(.1	)		(.1	)
Redemption of debentures issued to financing trust			-			(25.0	)
Issuances of long-term debt			-			120.0
Reacquisition of long-term debt			(25.6	)		(158.1	)
Issuances of short-term debt, net			84.4			76.9
Other financing activities, net			-			(1.1	)
Net Cash From (Used By) Financing Activities			10.8			(60.6	)

Net Decrease in Cash and Cash Equivalents			-			(102.2	)
Cash and Cash Equivalents at Beginning of Period			4.2			107.2

CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	4.2		$	5.0

NON CASH ACTIVITIES
Excess depreciation reserve transferred to regulatory liabilities		$	131.0		$	-

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

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

ATLANTIC CITY ELECTRIC COMPANY

(1)ORGANIZATION

Atlantic City Electric Company (ACE) is engaged in the generation, transmission and distribution of electricity in southern New Jersey. Additionally, ACE provides Basic Generation Service (BGS), which is the supply of electricity at regulated rates to retail customers in its territory who do not elect to purchase electricity from a competitive supplier. ACE's service territory covers approximately 2,700 square miles and has a population of approximately 998,000. ACE is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI). Because PHI is a public utility holding company registered under the Public Utility Holding Company Act of 1935 (PUHCA), the relationship between PHI and ACE and certain activities of ACE are subject to the regulatory oversight of the Securities and Exchange Commission (SEC) under PUHCA.

(2) ACCOUNTING POLICY, PRONOUNCEMENTS, AND OTHER DISCLOSURES

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 SEC, 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, 2004. In the opinion of ACE's management, the consolidated financial statements contain all adjustments (which all are of a normal recurring nature) necessary to fairly state ACE's financial condition as of June 30, 2005, its results of operations for the three and six months ended June 30, 2005, and its cash flows for the six months ended June 30, 2005 in accordance with GAAP. Interim results for the three and six months ended June 30, 2005 may not be indicative of results that will be realized for the full year ending December 31, 2005 since the sales of electric energy are seasonal. Additionally, certain prior period balances have been reclassified in order to conform to current period presentation.

FIN 45

As of June 30, 2005, ACE did not have material obligations under guarantees or indemnifications issued or modified after December 31, 2002, which are required to be recognized as liabilities on its consolidated balance sheets.

FIN 46R

ACE has power purchase agreements (PPAs) with a number of entities including three non-utility generation contracts (NUGs). Due to a variable element in the pricing structure of the NUGs, ACE potentially assumes the variability in the operations of the plants of these entities and therefore has a variable interest in the entities. As required by FIN 46R, ACE continued to conduct exhaustive efforts to obtain information from these entities, but was unable to obtain

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sufficient information to conduct the analysis required under FIN 46R 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 46R for enterprises that have conducted exhaustive efforts to obtain the necessary information.

Net purchase activities with the counterparties to the NUGs in the three and six months ended June 30, 2005 and 2004 were approximately $74 million and $63 million and $154 million and $130 million, respectively, of which $67 million and $56 million and $138 million and $115 million, respectively, related to power purchases under the NUGs. ACE does not have exposure to loss under the PPA agreements since cost recovery will be achieved from its customers through regulated rates.

Components of Net Periodic Benefit Cost/(Income)

The following Pepco Holdings' information is for the three months ended June 30, 2005 and 2004.

		Pension Benefits						Other Post-Retirement Benefits
		2005			2004			2005			2004
	(In Millions)
Service cost	$	9.6		$	8.4		$	2.1		$	2.4
Interest cost		23.6			23.5			8.4			8.3
Expected return on plan assets		(32.1	)		(32.3	)		(2.9	)		(2.8	)
Amortization of prior service cost		.3			.3			(.9	)		-
Amortization of net loss		2.7			(1.3	)		3.4			3.1
Net periodic benefit cost/(income)	$	4.1		$	(1.4	)	$	10.1		$	11.0

The following Pepco Holdings' information is for the six months ended June 30, 2005 and 2004.

		Pension Benefits						Other Post-Retirement Benefits
		2005			2004			2005			2004
	(In Millions)
Service cost	$	19.0		$	18.0		$	4.2		$	4.8
Interest cost		47.9			47.3			16.8			16.7
Expected return on plan assets		(62.8	)		(62.1	)		(5.4	)		(5.7	)
Amortization of prior service cost		.6			.5			(1.9	)		-
Amortization of net loss		5.2			3.3			5.9			6.2
Net periodic benefit cost	$	9.9		$	7.0		$	19.6		$	22.0

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Pension

The 2005 pension net periodic benefit cost for the three months ended June 30, of $4.1 million includes $2.0 million for ACE. The 2005 pension net periodic benefit cost for the six months ended June 30, of $9.9 million includes $4.1 million for ACE. The remaining pension net periodic benefit cost is for other PHI subsidiaries. The 2004 pension net periodic benefit cost/(income) for the three months ended June 30, of $(1.4) million includes $1.5 million for ACE. The 2004 pension net periodic benefit cost for the six months ended June 30, of $7.0 million includes $3.5 million for ACE. The remaining pension net periodic benefit cost is for other PHI subsidiaries.

The six months ended June 30, 2005 pension net periodic benefit cost reflects a reduction in the expected return on assets assumption from 8.75% to 8.50% effective January 1, 2005.

Pension Contributions

Other Post-Retirement Benefits

The 2005 other post-retirement net periodic benefit cost for the three months ended June 30, of $10.1 million includes $2.0 million for ACE. The 2005 other post-retirement net periodic benefit cost for the six months ended June 30, of $19.6 million includes $4.4 million for ACE. The remaining other post-retirement net periodic benefit cost is for other PHI subsidiaries. The 2004 other post-retirement net periodic benefit cost for the three months ended June 30, of $11.0 million includes $2.5 million for ACE. The 2004 other post-retirement net periodic benefit cost for the six months ended June 30, of $22.0 million includes $4.9 million for ACE. The remaining other post-retirement net periodic benefit cost is for other PHI subsidiaries.

The six months ended June 30, 2005 other post-retirement net periodic benefit cost reflects a reduction in the expected return on assets assumption from 8.75% to 8.50% effective January 1, 2005.

Debt

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its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time under the agreement may not exceed $500 million. Under the terms of the credit agreement, the companies are entitled to request increases in the principal amount of available credit up to an aggregate increase of $300 million, with any such increase proportionately increasing the credit limit of each of the respective borrowers and the $300 million sublimits for each of Pepco, DPL and ACE. The interest rate payable by the respective companies on utilized funds will be based on a pricing schedule determined by the credit rating of the borrower. Any indebtedness incurred under the Credit Agreement would be unsecured.

Effective Tax Rate

ACE's effective tax rate for the three months ended June 30, 2005 was 40% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit) partially offset by the flow-through of deferred investment tax credits.

ACE's effective tax rate for the three months ended June 30, 2004 was 41% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit) and the flow-through of certain book tax depreciation differences partially offset by the flow-through of deferred investment tax credits.

ACE's effective tax rate before extraordinary item for the six months ended June 30, 2005 was 39% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit) and the flow-through of certain book tax depreciation differences partially offset by the flow-through of deferred investment tax credits.

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ACE's effective tax rate for the six months ended June 30, 2004 was 41% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit) and the flow-through of certain book tax depreciation differences partially offset by the flow-through of deferred investment tax credits.

Extraordinary Item

On April 19, 2005, a settlement of ACE's electric distribution rate case was reached among ACE, the Staff of the New Jersey Board of Public Utilities (NJBPU), the New Jersey Ratepayer Advocate, and active intervenor parties. As a result of this settlement, ACE reversed $15.2 million ($9.0 million, after-tax) in accruals related to certain deferred costs that are now deemed recoverable. The after-tax credit to income of $9.0 million is classified as an extraordinary item (gain) since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.

Related Party Transactions

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including ACE, pursuant to a service agreement. 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 in consolidation and no profit results from these transactions. PHI Service Company costs directly charged or allocated to ACE for the three and six months ended June 30, 2005 and 2004 were $20.6 million and $20.1 million and $41.3 million and $42.3 million, respectively.

In addition to the PHI Service Company charges described above, ACE's Consolidated Statements of Earnings include the following expenses incurred by ACE in related party transactions:

	For the Quarters Ended June 30,				For the Six Months Ended June 30,
		2005		2004		2005		2004
	(In Millions)
Purchased power from Conectiv Energy Supply (included in Fuel and purchased energy)	$	17.5	$	6.6	$	30.8	$	6.6

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As of June 30, 2005 and December 31, 2004, ACE had the following balances on its Consolidated Balance Sheets due to and from related parties:

		2005			2004
		(In Millions)
Receivable from Related Party
King Street Assurance	$	2.6		$	2.6
Payable to Related Party (current)
PHI Service Company		(8.8	)		(10.3	)
Conectiv Energy Supply		(10.1	)		(4.5	)
DPL		(.3	)		-
Other Related Party Activity		(.4	)		(.2	)
Total Payable to Related Parties	$	(17.0	)	$	(12.4	)
Money Pool Balance with Pepco Holdings (included in cash and cash equivalents on the balance sheet)		.2			1.7

New Accounting Standards

SFAS No. 154

FIN 47

(3) 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.

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(4) COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Rate Proceedings

New Jersey

The settlement allows for an increase in ACE's base rates of approximately $18.8 million, $2.8 million of which will come from an increase in RARC revenue collections each year for the next four years. The $16 million of the base rate increase, not related to RARC collections, will be collected annually from ACE's customers until such time as base rates change pursuant to another base rate proceeding. The $18.8 million increase in base rate revenue is offset by a base rate revenue decrease in a similar amount in total resulting from a change in depreciation rate, as discussed below, similar to changes adopted by the NJBPU for other New Jersey electric utility companies. Overall, the settlement provides for a net decrease in annual revenues of approximately $.3 million, consisting of a $3.1 million reduction of distribution revenues offset by the $2.8 million increase in RARC revenue collections discussed above. The settlement specifies an overall rate of return of 8.14% and pro vides for a change in depreciation rates driven by a change in average service lives. In addition, the settlement provides for a change in depreciation technique from remaining life to whole life, including amortization of any calculated excess or deficiencies in the depreciation reserve. As a result of these changes, ACE had a net excess depreciation reserve. Accordingly, ACE recorded a regulatory liability in March 2005 by reducing its depreciation reserve by approximately $131 million. The regulatory liability will be amortized over 8.25 years and will result in a reduction of depreciation and amortization expense on ACE's consolidated statements of earnings. While the impact of the settlement is essentially revenue and cash neutral to ACE, there is a positive annual pre-tax earnings impact to ACE of approximately $20 million.

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Restructuring Deferral

In July 2003, the NJBPU issued a summary order, which (i) permitted ACE to begin collecting a portion of the deferred costs and reset rates to recover on-going costs incurred as a result of EDECA, (ii) approved the recovery of $125 million of the deferred balance over a ten-year amortization period beginning August 1, 2003, (iii) as described above under "Rate Proceedings--New Jersey," transferred to ACE's then pending base rate case for further consideration approximately $25.4 million of the deferred balance, and (iv) estimated the overall deferral balance as of July 31, 2003 at $195 million, of which $44.6 million was disallowed recovery by ACE. In July 2004, the NJBPU issued its final order in the restructuring deferral proceeding. The final order did not modify the amount of the disallowances set forth in the July 2003 summary order, but did provide a much more detailed analysis of evidence and other information relied on by the NJBPU as ju stification for the disallowances. ACE believes the record does not justify the level of disallowance imposed by the NJBPU. In August 2004, ACE filed with the NJ Superior Court a Notice of Appeal related to the July 2004 final order. ACE's initial brief is due on August 18, 2005. Final reply briefs are due by October 10, 2005. ACE cannot predict the outcome of this appeal.

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BGS Proceedings

New Jersey

Proposed Shut Down of B.L. England Generating Facility; Construction of Transmission Facilities

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ACE Auction of Generation Assets

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.

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In June 1992, the Environmental Protection Agency (EPA) identified ACE as a potentially responsible party (PRP) at the Bridgeport Rental and Oil Services Superfund Site in Logan Township, New Jersey. In September 1996, ACE along with other PRPs signed a consent decree with EPA and NJDEP to address remediation of the site. ACE's liability is limited to 0.232 percent of the aggregate remediation liability and thus far ACE has made contributions of approximately $105,000. Based on information currently available, ACE may be required to contribute approximately an additional $100,000. ACE believes that its liability at this site will not have a material adverse effect on its financial condition or results of operations.

In November 1991, NJDEP identified ACE as a PRP at the Delilah Road Landfill site in Egg Harbor Township, New Jersey. In 1993, ACE, along with other PRPs, signed an administrative consent order with NJDEP to remediate the site. The soil cap remedy for the site has been completed and the NJDEP conditionally approved the report submitted by the parties on the implementation of the remedy in January 2003. In March 2004, NJDEP approved a Ground Water Sampling and Analysis Plan. The results of groundwater monitoring over the first year of this ground water sampling plan will help to determine the extent of post-remedy operation and maintenance costs. In March 2003, EPA demanded from the PRP group reimbursement for EPA's past costs at the site, totaling $168,789. The PRP group objected to the demand for certain costs, but agreed to reimburse EPA approximately $19,000. Based on information currently available, ACE may be required to contribute approximately an additional $626 ,000. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial condition or results of operations.

Preliminary Settlement Agreement with the NJDEP

contingent upon the receipt of necessary approvals from the NJBPU, PJM, North American Electric Reliability Council (NERC), FERC, and other regulatory authorities and the receipt of permits to construct certain transmission facilities in southern New Jersey, ACE will permanently cease operation of the B.L. England generating facility by December 15, 2007. In the event that ACE is unable to shut down the B.L. England facility by December 15, 2007 through no fault of its own (e.g., because of failure to obtain the required regulatory approvals), B.L. England Unit 1 would be required to comply with stringent sulfur dioxide (SO₂), nitrogen oxide (NOx) and particulate matter emissions limits set forth in the preliminary settlement agreement by October 1, 2008, and B.L. England Unit 2 would be required to comply with these emissions limits by May 1, 2009. If ACE does not either shut down the B.L. England facility by December 15, 2007 or satisfy the emissions limits applicable in th e event shut down is not so completed, ACE would be required to pay significant monetary penalties.

to address ACE's appeal of NJDEP actions relating to NJDEP's July 2001 denial of ACE's request to renew a permit variance from sulfur-in-fuel requirements under New Jersey regulations, effective through July 30, 2001, that authorized Unit 1 at B.L.

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	England generating facility to burn bituminous coal containing greater than 1% sulfur, ACE will be permitted to combust coal with a sulfur content of greater than 1% at the B.L. England facility in accordance with the terms of B.L. England's current permit until December 15, 2007 and NJDEP will not impose new, more stringent short-term SO₂ emissions limits on the B.L. England facility during this period. By letter dated July 13, 2005, NJDEP extended, until October 30, 2005, the deadline for ACE to file an application to renew its current fuel authorization for the B.L. England generating plant, which is scheduled to expire on July 30, 2006.
·	to resolve any possible civil liability (and without admitting liability) for violations of the permit provisions of the New Jersey Air Pollution Control Act (APCA) and the Prevention of Significant Deterioration provisions of the Federal Clean Air Act (CAA) relating to modifications that may have been undertaken at the B.L. England facility, ACE paid a $750,000 civil penalty to NJDEP on June 1, 2004. To compensate New Jersey for other alleged violations of the APCA and/or the CAA, ACE will undertake environmental projects valued at $2 million, which are beneficial to the state of New Jersey and approved by the NJDEP in a consent order or other final settlement document.
·	ACE will submit all federally required studies and complete construction of facilities, if any, necessary to satisfy the EPA's new cooling water intake structure regulations in accordance with the schedule that NJDEP established in the recent renewal of the New Jersey Pollutant Discharge Elimination System permit for the B.L. England facility. The schedule takes into account ACE's agreement, provided that all regulatory approvals are obtained, to shut down the B.L. England facility by December 15, 2007.
·	to resolve any possible civil liability (and without admitting liability) for natural resource damages resulting from groundwater contamination at the B.L. England facility, Conectiv Energy's Deepwater generating facility and ACE's operations center near Pleasantville, New Jersey, ACE and Conectiv will pay NJDEP $674,162 or property of equivalent value and will remediate the groundwater contamination at all three sites. If subsequent data indicate that groundwater contamination is more extensive than indicated in NJDEP's preliminary analysis, NJDEP may seek additional compensation for natural resource damages.

(5) CHANGES IN ACCOUNTING ESTIMATES

During the second quarter of 2005, ACE recorded the impact of a reduction in estimated unbilled revenue, primarily reflecting an increase in the estimated amount of power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). These changes in accounting estimates reduced second quarter earnings by approximately $6.4 million.

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(6) SUBSEQUENT EVENT

IRS Revenue Ruling

During 2001, ACE changed its methods of accounting with respect to capitalizable construction costs for income tax purposes, which allow ACE to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through June 30, 2005, these accelerated deductions have generated approximately $69 million in tax cash flow benefits, primarily attributable to its 2001 tax returns. On August 2, 2005, the IRS issued Revenue Ruling 2005-53 (the Ruling) that will limit the ability of ACE to utilize this method of accounting. Under the Ruling, ACE may have to recapitalize and depreciate a portion of these expenses and repay a portion of the past income tax benefits, along with interest thereon.

ACE believes that its tax position was appropriate based on applicable statutes, regulations, and case law in effect at the time the companies made the change in accounting method for income tax purposes. However, there is no assurance that ACE's position will prevail.

The tax benefits derived from the change in accounting method have been accounted for as temporary differences in determining ACE's deferred income tax balances for financial reporting purposes. Consequently, the repayment of the tax benefits, if required, would affect cash flows and deferred income tax balances, but would not affect earnings, other than a charge for the accrual of related interest.

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

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

Registrants	Page No.
Pepco Holdings	102
Pepco	148
DPL	168
ACE	176

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

PEPCO HOLDINGS

GENERAL OVERVIEW

Pepco Holdings, Inc. (PHI or Pepco Holdings) is a public utility holding company that, through its operating subsidiaries, is engaged primarily in two principal business operations:

·	electricity and natural gas delivery (Power Delivery), and
·	competitive energy generation, marketing and supply (Competitive Energy).

ThePower Deliverybusinessis the largest component of PHI's business. For the three and six months ended June 30, 2005, the operating revenues of the Power Delivery business (including intercompany amounts) were equal to 57% and 59% of PHI's consolidated operating revenues and the operating income of the Power Delivery business (including income from intercompany transactions) was equal to 66% and 71% of PHI's consolidated operating income. The Power Delivery business consists primarily of the transmission, distribution and default supply of electric power, which was responsible for 95% and 92% of Power Delivery's three and six months ended June 30, 2005 operating revenues, and the distribution of natural gas, which contributed 5% and 8% of Power Delivery's 2005 operating revenues over these periods. Power Delivery represents one operating segment for financial reporting purposes.

The Power Delivery business is conducted by three regulated utility subsidiaries: Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE), each of which 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 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 service varies by jurisdiction as follows:

	Delaware	Provider of Last Resort service (POLR) -- before May 1, 2006 Standard Offer Service (SOS) -- on and after May 1, 2006
	District of Columbia	Standard Offer Service
	Maryland	Standard Offer Service
	New Jersey	Basic Generation Service (BGS)
	Virginia	Default Service

PHI and its subsidiaries refer to this supply service in each of the jurisdictions generally as Default Electricity Supply.

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The rates each company is permitted to charge for the transmission of electricity are regulated by the Federal Energy Regulatory Commission (FERC).

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.

Power Delivery's operating revenue and income are seasonal, and weather patterns may have a material impact on operating results.

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. These operations are conducted through subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv Energy) and Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), each of which is treated as a separate operating segment for financial reporting purposes. For the three and six months ended June 30, 2005, theoperating revenues of the Competitive Energy business (including intercompany amounts), were equal to 53% and 50% of PHI's consolidated operating revenues and the operating income of the Competitive Energy business (including operating income from intercompany transactions) was 24% and 19% of PHI's consolidated operating income. Of these segments' operating revenues for the three and six months ended June 30, 2005, an amount equal to 14% of its operating revenues was attributable to electric energy, electric capacity, and natural gas sold to the Power Delivery segment.

Conectiv Energy provides wholesale power, capacity and ancillary services in the wholesale markets administered by PJM Interconnection, LLC (PJM) and also supplies electricity to other wholesale market participants. Conectiv Energy has a power supply agreement under which it provides DPL with Default Electricity Supply for distribution to customers in Delaware and Virginia. Conectiv Energy also supplies a portion of the Default Electricity Supply for DPL's Maryland load, a portion of ACE's load, as well as load shares of other mid-Atlantic utilities. Conectiv Energy obtains the electricity required to meet its power supply obligations from its own generation plants, under bilateral contract purchases from other wholesale market participants and from purchases in the PJM wholesale market. Conectiv Energy also sells natural gas and fuel oil to very large end-users and to wholesale market participants under bilateral agreements.

Pepco Energy Services sells retail electricity and natural gas and provides integrated energy management services, primarily in the mid-Atlantic region. Pepco Energy Services also provides high voltage construction and maintenance services to utilities and other customers throughout the United States and low voltage electric and telecommunication construction and maintenance services primarily in the Washington, D.C. area.

The primary objectives of the Competitive Energy business are to manage Conectiv Energy's generation assets to match wholesale energy supply with load and to capture retail energy supply and service opportunities in the mid-Atlantic region through Pepco Energy Services. The financial results of the Competitive Energy business can be significantly affected by wholesale and retail energy prices, the cost of fuel to operate the Conectiv Energy plants, and the cost of purchased energy necessary to meet its power supply obligations.

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In order to lower its financial exposure related to commodity price fluctuations and provide a more predictable earnings stream, the Competitive Energy business frequently enters into contracts to hedge the power output of its generation facilities, the costs of fuel used to operate those facilities and its energy supply obligations.

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

Over the last several years, PHI has discontinued its investments in non-energy related businesses, including the sale of its aircraft portfolio and the sale of its 50% interest in Starpower Communications LLC (Starpower). These activities previously had been conducted through Potomac Capital Investment Corporation (PCI) and Pepco Communications LLC, respectively. PCI's current activities are limited to the management of a portfolio of cross-border energy sale-leaseback transactions with a book value at June 30, 2005 of approximately $1.2 billion. PCI does not plan on making new investments and will focus on maintaining the earnings stream from its energy leveraged leases. These remaining operations constitute a fourth operating segment, called "Other Non-Regulated," for financial reporting purposes.

For additional information including information about PHI's business strategy refer to Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in PHI's Annual Report on Form 10-K for the year ended December 31, 2004.

EARNINGS OVERVIEW

Three Months Ended June 30, 2005 Compared to Three Months Ended June 30, 2004

PHI's net income for the three months ended June 30, 2005 was $64.0 million compared to $90.4 million for the three months ended June 30, 2004.

Net income for the second quarter 2004 included the (charges) and/or credits set forth below (which are presented net of tax and in millions of dollars). The segment that recognized the credit is also indicated.

·	Power Delivery -	Gain on Vineland distribution assets condemnation settlement	$ 8.6
·	Conectiv Energy -	Gain on disposition associated with a co-generation joint venture	$ 6.6
·	Other Non-Regulated -	An impairment charge which reduced the value of the Starpower investment to $28 million at June 30, 2004	$(7.3)

Excluding the items listed above, net income would have been $82.5 million in the second quarter of 2004.

PHI's net income for the three months ended June 30, 2005 compared to the three months ended June 30, 2004 is set forth in the table below:

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		2005			2004			Change
		(Dollars in Millions)
Power Delivery	$	48.1		$	72.5		$	(24.4	)
Conectiv Energy		12.9			24.5			(11.6	)
Pepco Energy Services		8.7			3.5			5.2
Other Non-Regulated		8.9			6.9			2.0
Corporate & Other		(14.6	)		(17.0	)		2.4
Total PHI Net Income (GAAP)	$	64.0		$	90.4		$	(26.4	)

Discussion of Segment Net Income Variances:

Power Delivery's lower earnings of $24.4 million are primarily due to the following: (i) $4.4 million of lower earnings related to Pepco's adjustment to correct the unbilled revenue amount that was reported in the first quarter of 2005, (ii) $7.4 million of lower earnings was due to reductions by each of DPL and ACE in estimated unbilled revenue, primarily reflecting an increase in the amount of estimated power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers), (iii) $3.5 million of lower earnings related to reduced sales (3.9% GwH decrease/9.6% bcf decrease)/customer mix/weather (28.8% cooling degree days decrease), (iv) $8.6 million of lower earnings related to the second quarter 2004 gain associated with the Vineland distribution assets condemnation settlement, and (v) $3.1 million of higher operation and maintenance costs (attributable primarily to employee benefit related costs; which were partiall y offset by decreased PJM administrative office expenses); partially offset by (vi) $1.7 million of increased earnings related to the gain on the sale of a Pepco substation, and (vii) $1.0 million of lower interest expense.

Conectiv Energy's lower earnings of $11.6 million are primarily due to the following: (i) $6.6 million of lower earnings because of the gain on disposition associated with a co-generation joint venture recorded in the second quarter of 2004, (ii) $6.0 million of lower Full Requirements Load Service earnings as a result of lower sales and higher costs associated with serving load obligations, and (iii) $3.2 million of lower earnings related to Other Power, Oil & Gas Marketing costs and higher miscellaneous expenses; partially offset by (iv) $4.1 million increase in merchant generation earnings, primarily because of higher spark spreads in the second quarter of 2005.

Pepco Energy Services' higher earnings of $5.2 million are primarily due to higher earnings from its retail electric commodity business, primarily resulting from its increased load acquisition.

Other Non-Regulated higher earnings of $2.0 million are primarily due to the following: (i) $7.3 million impairment charge which reduced the value of the Starpower investment in the second quarter of 2004; partially offset by (ii) $5.1 million decrease in financing/investment earnings primarily related to preferred stock dividends and gains derived on the sale of preferred stock in 2004.

Corporate and Other higher earnings of $2.4 million are primarily due to a reduction in net interest expense.

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Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004 Results

PHI's net income for the six months ended June 30, 2005 was $119.5 million compared to $141.6 million for the six months ended June 30, 2004.

Net income for the six months ended June 30, 2005 included the (charges) and/or credits set forth below (which are presented net of tax and in millions of dollars). The segment that recognized the (charge) or credit is also indicated.

·	Favorable impact of $5.1 related to the ACE base rate case settlement as follows:
		Power Delivery
			Ordinary loss from write-offs of disallowance of regulatory assets net of reserve	$(3.9)
			Extraordinary gain from reversal of restructuring reserves	9.0
		Power Delivery aggregate impact		$ 5.1

Excluding the items listed above, net income would have been $114.4 million for the six months ended June 30, 2005.

Net income for the six months ended June 30, 2004 included the (charges) and/or credits set forth below (which are presented net of tax and in millions of dollars). The segment that recognized the (charge) or credit (or, if not attributable to an operating segment, Corporate and Other) is also indicated.

·	An aggregate of $13.2 in tax benefits related to issuance of a local jurisdiction's final consolidated tax return regulations, which were retroactive to 2001. Effects by segment were:
		Power Delivery		$ .8
		Pepco Energy Services		1.5
		Other Non-Regulated		8.8
		Corporate & Other		2.1
		PHI Consolidated		$13.2
·	Power Delivery -		Gain on Vineland distribution assets condemnation settlement	$ 8.6
·	Conectiv Energy -		Gain on disposition associated with a co-generation joint venture	$ 6.6
·	Other Non-Regulated -		An impairment charge which reduced the value of the Starpower investment to $28 million at June 30, 2004	$(7.3)

Excluding the items listed above, net income would have been $120.5 million for the six months ended June 30, 2004.

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PHI's net income for the six months ended June 30, 2005 compared to the six months ended June 30, 2004 is set forth in the table below:

		2005			2004			Change
		(Dollars in Millions)
Power Delivery	$	100.4		$	113.3		$	(12.9	)
Conectiv Energy		16.0			29.6			(13.6	)
Pepco Energy Services		11.1			6.8			4.3
Other Non-Regulated		22.5			27.0			(4.5	)
Corporate & Other		(30.5	)		(35.1	)		4.6
Total PHI Net Income (GAAP)	$	119.5		$	141.6		$	(22.1	)

Discussion of Segment Net Income Variances:

Power Delivery's lower earnings of $12.9 million are primarily due to the following: (i) $7.4 million of lower earnings was due to reductions by each of DPL and ACE in estimated unbilled revenue, primarily reflecting an increase in the amount of estimated power line losses, (ii) $4.6 million of lower earnings related to reduced sales [(2.9% GwH decrease/5.4% bcf decrease)/customer mix/weather (28.9% cooling degree days decrease)], and (iii) $12.5 million of lower earnings because of a gain on the sale of assets and the condemnation settlement of assets in 2004, of which $8.6 million was associated with the Vineland distribution assets condemnation settlement and $3.9 million was associated with the sale of assets; partially offset by (iv) $5.1 million increase related to the ACE base rate case settlement (described in "Extraordinary Item" below), (v) $3.2 million increase from the implementation of the competitive bid procedure for Standard Offer Service (SOS) approved by the Maryland and the District of Columbia public service commissions effective June and July 2004 and February 2005, respectively, and (vi) $3.6 million of lower interest expense.

Conectiv Energy's lower earnings of $13.6 million are due to the following: (i) $6.6 million of lower earnings because of the gain on disposition associated with a co-generation joint venture in the second quarter of 2004 and (ii) $2.8 million of lower Full Requirements Load Service earnings as a result of higher costs associated with serving load obligations and (iii) $4.2 million of lower earnings related to Other Power, Oil & Gas Marketing costs and higher miscellaneous expenses.

Pepco Energy Services' higher earnings of $4.3 million are primarily due to the following: (i) $8.3 million of higher earnings from its retail commodity business; partially offset by (ii) $1.7 million of lower generation earnings from its Benning and Buzzard power plants, (iii) $1.5 million decrease related to the 2004 tax benefit related to the issuance of a local jurisdiction's final consolidated tax return regulations (described above), and (iv) $1.1 million of lower earnings from its services activities.

Other Non-Regulated lower earnings of $4.5 million are primarily due to the following: (i) $8.8 million decrease related to the 2004 tax benefit related to issuance of a local jurisdiction's final consolidated tax return regulations (described above), (ii) $3.6 million decrease due to the gain on sale of aircraft leases in the first quarter of 2004 and (iii) $4.3 million decrease in financing/investment earnings primarily related to preferred stock dividends and gains derived on the sale of preferred stock in 2004; partially offset by (iv) $7.3 million increase related to an

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impairment charge which reduced the value of the Starpower investment recorded in the second quarter of 2004 and (v) $4.8 million related to the gain on the sale of PCI's solar electric generation stations (SEGS) investment in 2005.

Corporate and Other higher earnings of $4.6 million are primarily due to the following: (i) $8.0 million reduction in net interest expense; partially offset by (ii) a $2.1 million decrease related to the 2004 tax benefit related to issuance of a local jurisdiction's final consolidated tax return regulations (described above).

CONSOLIDATED RESULTS OF OPERATIONS

The accompanying results of operations discussion is for the three months ended June 30, 2005 compared to the three months ended June 30, 2004. All amounts in the tables (except sales and customers) are in millions.

Operating Revenue

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

	2005			2004			Change
Power Delivery	$	974.2		$	1,073.5		$	(99.3	)
Conectiv Energy		584.2			565.4			18.8
Pepco Energy Services		320.2			243.5			76.7
Other Non-Regulated		20.5			24.2			(3.7	)
Corporate and Other		(187.0	)		(215.1	)		28.1
Total Operating Revenue	$	1,712.1		$	1,691.5		$	20.6

Power Delivery Business

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

	2005		2004		Change
Regulated T&D Electric Revenue	$	365.8	$	388.8	$	(23.0	)
Default Supply Revenue		547.3		619.0		(71.7	)
Other Electric Revenue		13.6		16.4		(2.8	)
Total Electric Operating Revenue		926.7		1,024.2		(97.5	)

Regulated Gas Revenue		35.2		29.4		5.8
Other Gas Revenue		12.3		19.9		(7.6	)
Total Gas Operating Revenue		47.5		49.3		(1.8	)

Total Power Delivery Operating Revenue	$	974.2	$	1,073.5	$	(99.3	)

Regulated Transmission and Distribution (T&D) Electric Revenue consists of revenue from the transmission and the delivery of electricity to its customers within PHI's service territories at regulated rates.

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Default Supply Revenue is the revenue received from Default Electricity Supply. The costs related to the supply of electricity are included in Fuel and Purchased Energy and Other Services Cost of Sales.

Other Electric Revenue consists of utility-related work and services performed on behalf of customers including other utilities.

Regulated Gas Revenue consists of revenue DPL receives for on-system natural gas sales and the transportation of natural gas for customers within PHI's service territories at regulated rates.

Other Gas Revenue consists of off-system natural gas sales and the release of excess system capacity.

Electric Operating Revenue

Regulated T&D Electric Revenue	2005		2004		Change

Residential	$	132.6	$	138.3	$	(5.7	)
Commercial		164.7		182.0		(17.3	)
Industrial		8.8		9.3		(.5	)
Other (Includes PJM)		59.7		59.2		.5
Total Regulated T&D Electric Revenue	$	365.8	$	388.8	$	(23.0	)

Regulated T&D Electric Sales (GwH)	2005		2004		Change

Residential		3,632		4,011		(379	)
Commercial		6,608		7,115		(507	)
Industrial		1,103		1,168		(65	)
Other		57		57		-
Total Regulated T&D Electric Sales		11,400		12,351		(951	)

Regulated T&D Electric Customers (000s)	2005		2004		Change

Residential		1,576		1,573		3
Commercial		195		191		4
Industrial		2		2		-
Other		2		2		-
Total Regulated T&D Electric Customers		1,775		1,768		7

The ACE, DPL, and Pepco 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, casinos, government, insurance, real estate, strip mall, stand alone construction, and tourism.

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

Regulated T&D Revenue decreased by $23.0 million due to the following: (i) $7.5 million related to Pepco's adjustment to correct the unbilled revenue amount that was reported in the first quarter of 2005, (ii) $5.2 million due to reductions by each of DPL and ACE in estimated unbilled revenue, primarily reflecting an increase in the amount of estimated power line losses, (iii) $11.2 million due to milder weather as the result of a 28.8% decrease in cooling degree days in 2005 and (iv) $1.5 million decrease due to changes in customer class mix, partially offset by (v) $3.5 million increase in tax pass-throughs, principally a county surcharge rate increase, (offset in Other Taxes). Delivery sales for the three months ended June 30, 2005 were approximately 11,400 GwH compared to approximately 12,351 GwH for the comparable period in 2004.

Default Electricity Supply

Default Supply Revenue	2005		2004		Change

Residential	$	225.3	$	216.5	$	8.8
Commercial		211.8		287.8		(76.0	)
Industrial		31.5		36.5		(5.0	)
Other (Includes PJM)		78.7		78.2		.5
Total Default Supply Revenue	$	547.3	$	619.0	$	(71.7	)

Default Electricity Supply Sales (GwH)	2005		2004		Change

Residential		3,558		3,767		(209	)
Commercial		3,154		5,002		(1,848	)
Industrial		502		625		(123	)
Other		44		52		(8	)
Total Default Electricity Supply Sales		7,258		9,446		(2,188	)

Default Electricity Supply Customers (000s)	2005		2004		Change

Residential		1,537		1,484		53
Commercial		178		177		1
Industrial		2		2		-
Other		2		2		-
Total Default Electricity Supply Customers		1,719		1,665		54

Default Supply Revenue decreased by $71.7 million primarily due to lower sales driven by commercial customer migration as a result of market based SOS beginning in Maryland in July 2004 and in the District of Columbia in February 2005 (offset in Fuel and Purchased Energy) and $10.7 million due to reductions by each of DPL and ACE in estimated unbilled revenue, primarily reflecting an increase in the amount of estimated power line losses.

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Gas Operating Revenue

Regulated Gas Revenue	2005		2004		Change

Residential	$	21.2	$	18.0	$	3.2
Commercial		10.5		8.6		1.9
Industrial		2.4		1.8		.6
Transportation and Other		1.1		1.0		.1
Total Regulated Gas Revenue	$	35.2	$	29.4	$	5.8

Regulated Gas Sales (Bcf)	2005		2004		Change

Residential		1.0		1.1		(.1	)
Commercial		.7		.7		-
Industrial		.2		.2		-
Transportation and Other		1.2		1.4		(.2	)
Total Regulated Gas Sales		3.1		3.4		(.3	)

Regulated Gas Customers (000s)	2005		2004		Change

Residential		109		108		1
Commercial		9		9		-
Industrial		-		-		-
Transportation and Other		-		-		-
Total Regulated Gas Customers		118		117		1

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

·	Commercial activity in the region includes banking and other professional services, government, insurance, real estate, strip mall, stand alone construction, and tourism.
·	Industrial activity in the region includes automotive, chemical, and pharmaceutical.

Regulated Gas Revenue increased by $5.8 million due to a $5.1 million increase in the Gas Cost Rate (which became effective November 1, 2004) from higher natural gas commodity costs (offset in Gas Purchased).

Other Gas Revenue decreased by $7.6 million largely due to significantly fewer off-system sales compared to the same period last year, which was partially offset by increased capacity release volumes (offset in Gas Purchased).

Competitive Energy Business

The following table divides the operating revenues of the Competitive Energy business among its major business activities.

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	2005		2004		Change

Merchant Generation	$	110.3	$	121.0	$	(10.7	)
Requirements Load Service (POLR, BGS, SOS)		212.2		261.2		(49.0	)
Oil & Gas Marketing Services and Other		261.7		183.2		78.5
Total Conectiv Energy Operating Revenue	$	584.2	$	565.4	$	18.8

Pepco Energy Services	$	320.2	$	243.5	$	76.7

·	Merchant Generation experienced a decrease of $10.7 million primarily due to 27% lower unit output for the quarter, partially offset by higher energy sales prices.
·	Requirements Load Service experienced a decrease of $49.0 million due to a decrease in DPL's POLR load because of the implementation of competitive bidding for wholesale supply in Maryland and Virginia, and lower New Jersey BGS sales.
·	Oil and Gas Marketing Services and Other increased by $78.5 million primarily due to increased wholesale natural gas sales and higher natural gas prices.

The increase in Pepco Energy Services' operating revenue of $76.7 million is primarily due to increased commercial and industrial load acquisition by Pepco Energy Services in 2005 at somewhat higher prices than in the 2004 quarter. As of June 30, 2005, Pepco Energy Services had 2,540 megawatts of commercial and industrial load, as compared to 1,475 megawatts of commercial and industrial load at the end of the second quarter of 2004.

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:

	2005			2004			Change
Power Delivery	$	569.7		$	626.4		$	(56.7	)
Conectiv Energy		519.2			496.1			23.1
Pepco Energy Services		287.5			217.0			70.5
Other Non-Regulated		-			-			-
Corporate and Other		(186.3	)		(216.2	)		29.9
Total	$	1,190.1		$	1,123.3		$	66.8

Power Delivery's Fuel and Purchased Energy costs decreased by $56.7 million due to the following: (i) $53.4 million decrease due to customer migration, (ii) $5.5 million lower PJM network transmission expenses, (iii) $3.9 million reduced fuel costs for B.L. England, (iv) $1.9 million decrease for gas commodity fuel costs, (v) $1.3 million decrease in costs due to the curtailment of the Generation Procurement Credit (GPC) as a result of the new Default Electricity Supply agreements, partially offset by (vi) $9.3 million higher average energy costs,
the result of the new Default Electricity Supply rates for New Jersey beginning in June 2004 and June 2005.

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The following table divides the fuel and purchased energy and other services costs of sales of the Competitive Energy business among its major business activities.

	2005		2004		Change

Merchant Generation	$	54.6	$	72.2	$	(17.6	)
Requirements Load Service (POLR, BGS, SOS)		203.3		242.3		(39.0	)
Oil & Gas Marketing Services and Other		261.3		181.6		79.7
Total Conectiv Energy Fuel and Purchased Energy and Other Services Cost of Sales	$	519.2	$	496.1	$	23.1

Pepco Energy Services	$	287.5	$	217.0	$	70.5

The increase of $23.1 million in Conectiv Energy's fuel, purchased energy and other services cost of sales is attributable to the following:

·	Merchant Generation costs decreased by $17.6 million mainly due to 27% lower unit output for the quarter.
·	Requirements Load Service costs decreased by $39.0 million due to a decrease in DPL's POLR load because of the implementation of competitive bidding on wholesale supply in Maryland and Virginia, and lower New Jersey BGS sales.
·	Oil and Gas Marketing Services and Other costs increased by $79.7 million primarily due to increased wholesale natural gas sales and higher natural gas prices.

The increase in Pepco Energy Services' fuel and purchased energy and other services cost of sales of $70.5 million resulted from higher volumes of electricity purchased at higher prices in the 2005 quarter to serve customers.

Other Operation and Maintenance

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

	2005			2004			Change
Power Delivery	$	149.2		$	144.9		$	4.3
Conectiv Energy		24.1			24.0			.1
Pepco Energy Services		15.0			17.5			(2.5	)
Other Non-Regulated		1.2			1.8			(.6	)
Corporate and Other		(2.2	)		(3.4	)		1.2
Total	$	187.3		$	184.8		$	2.5

PHI's other operation and maintenance increased by $2.5 million to $187.3 million in the 2005 quarter from $184.8 million in the 2004 quarter primarily due to $6.2 million higher employee benefit related expenses, partially offset by $2.1 million lower PJM administrative expenses due to market based SOS.

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Depreciation and Amortization

PHI's depreciation and amortization expenses decreased by $7.6 million to $101.8 million in the 2005 quarter from $109.4 million in the 2004 quarter primarily due to a $3.4 million decrease in New Jersey bondable transition property and a decrease of $2.7 million related to the disposition of non-regulated assets.

Other Taxes

Other taxes increased by $12.0 million to $76.2 million in the 2005 quarter from $64.2 million in the 2004 quarter. This increase was primarily due to (i) $5.5 million increase due to property tax accruals, (ii) $5.4 million higher pass-throughs of higher county surcharge rate increase (offset in Regulated T&D Electric Revenue), partially offset by (iii) $2.0 million lower delivery taxes (offset in Regulated T&D Electric Revenue).

Deferred Electric Service Costs

Deferred Electric Service Costs (DESC) decreased by $12.2 million to an $18.2 million credit to Operating Expense for the three months ended June 30, 2005 from a $6.0 million credit to Operating Expense for the three months ended June 30, 2004. The $12.2 million decrease primarily represents (i) $9.5 million increase associated with a scheduled change in the levels of NUG contract payments, (ii) $3.8 million increase in NUG energy costs, offset by (iii) $1.0 million decrease in societal benefits charges primarily related to elimination of a customer credit and lower clean energy program expenses. On ACE's balance sheet a regulatory asset includes an under-recovery in the amount of $96.8 million as of June 30, 2005. This amount is net of a $47.3 million reserve on previously disallowed items under appeal.

Gain on Sale of Assets

PHI's gain on sale of assets in the 2005 quarter primarily represents a $2.8 million gain from the sale of Pepco land. The gain in the 2004 quarter primarily represents a $14.4 million gain from the condemnation settlement with the City of Vineland, New Jersey relating to the transfer of ACE's distribution assets and customer accounts to the city.

Other Income (Expenses)

PHI's other expense (which is net of other income) decreased $6.7 million to $73.9 million in the 2005 quarter from $80.6 million in the 2004 quarter primarily due to the following (i) an $11.2 million impairment charge on the Starpower investment that was recorded during the second quarter of 2004, (ii) $4.6 million higher other income, and (iii) a reduction in net interest expense of $3.5 million mainly due to lower debt outstanding, partially offset by a pre-tax gain of $11.2 million on a distribution from a co-generation joint-venture that was recognized by Conectiv Energy during the second quarter of 2004.

Income Tax Expense

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certain book tax depreciation differences, partially offset by the flow-through of deferred investment tax credits and tax benefits related to certain leveraged leases.

The accompanying results of operations discussion is for the six months ended June 30, 2005 compared to the six months ended June 30, 2004. All amounts in the tables (except sales and customers) are in millions.

Operating Revenue

A detail of the components of PHI's consolidated operating revenues is as follows:

	2005			2004			Change
Power Delivery	$	2,078.9		$	2,112.7		$	(33.8	)
Conectiv Energy		1,093.6			1,153.2			(59.6	)
Pepco Energy Services		672.8			554.2			118.6
Other Non-Regulated		41.0			45.3			(4.3	)
Corporate and Other		(369.4	)		(409.8	)		40.4
Total Operating Revenue	$	3,516.9		$	3,455.6		$	61.3

Power Delivery Business

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

	2005		2004		Change
Regulated T&D Electric Revenue	$	745.7	$	761.0	$	(15.3	)
Default Supply Revenue		1,143.9		1,168.4		(24.5	)
Other Electric Revenue		30.1		34.1		(4.0	)
Total Electric Operating Revenue		1,919.7		1,963.5		(43.8	)

Regulated Gas Revenue		127.9		110.9		17.0
Other Gas Revenue		31.3		38.3		(7.0	)
Total Gas Operating Revenue		159.2		149.2		10.0

Total Power Delivery Operating Revenue	$	2,078.9	$	2,112.7	$	(33.8	)

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Regulated T&D Electric Revenue	2005		2004		Change

Residential	$	278.5	$	289.4	$	(10.9	)
Commercial		333.4		334.9		(1.5	)
Industrial		18.3		17.8		.5
Other (Includes PJM)		115.5		118.9		(3.4	)
Total Regulated T&D Electric Revenue	$	745.7	$	761.0	$	(15.3	)

Regulated T&D Electric Sales (GwH)	2005		2004		Change

Residential		8,399		8,911		(512	)
Commercial		13,477		13,801		(324	)
Industrial		2,123		2,222		(99	)
Other		127		129		(2	)
Total Regulated T&D Electric Sales		24,126		25,063		(937	)

Regulated T&D Electric Customers (000s)	2005		2004		Change

Residential		1,576		1,573		3
Commercial		195		191		4
Industrial		2		2		-
Other		2		2		-
Total Regulated T&D Electric Customers		1,775		1,768		7

Regulated T&D Revenue decreased by $15.3 million due to the following: (i) $13.6 million due to milder weather, the result of a 28.7% decrease in cooling degree days in 2005, (ii) $5.2 million due to reductions by each of DPL and ACE in estimated unbilled revenue, primarily reflecting an increase in the amount of estimated power line losses, (iii) $4.1 million decrease due to changes in customer class mix, and (iv) $3.8 decrease in other sales and rate variances, partially offset by (v) $11.4 million increase in tax pass-throughs, principally a county surcharge rate increase (offset in Other Taxes). Delivery sales for the six months ended June 30, 2005 were approximately 24,126 GwH compared to approximately 25,063 GwH for the comparable period in 2004.

Default Electricity Supply

Default Supply Revenue	2005		2004		Change

Residential	$	492.1	$	439.9	$	52.2
Commercial		429.6		490.9		(61.3	)
Industrial		61.2		70.6		(9.4	)
Other (Includes PJM)		161.0		167.0		(6.0	)
Total Default Supply Revenue	$	1,143.9	$	1,168.4	$	(24.5	)

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Default Electricity Supply Sales (GwH)	2005		2004		Change

Residential		8,148		8,377		(229	)
Commercial		7,120		9,634		(2,514	)
Industrial		984		1,205		(221	)
Other		97		112		(15	)
Total Default Electricity Supply Sales		16,349		19,328		(2,979	)

Default Electricity Supply Customers (000s)	2005		2004		Change

Residential		1,537		1,484		53
Commercial		178		177		1
Industrial		2		2		-
Other		2		2		-
Total Default Electricity Supply Customers		1,719		1,665		54

Default Supply Revenue decreased by $24.5 million primarily due to lower industrial and commercial sales as a result of market based SOS beginning in Maryland in July 2004 and in the District of Columbia in February 2005 (offset in Fuel and Purchased Energy) and a decrease of $10.7 million resulting from reductions by each of DPL and ACE in estimated unbilled revenue, primarily reflecting an increase in the amount of estimated power line losses.

Other Electric Revenue decreased $4.0 million primarily due to lower customer requested work and miscellaneous revenue.

Gas Operating Revenue

Regulated Gas Revenue	2005		2004		Change

Residential	$	78.4	$	69.3	$	9.1
Commercial		41.4		34.9		6.5
Industrial		5.7		4.5		1.2
Transportation and Other		2.4		2.2		.2
Total Regulated Gas Revenue	$	127.9	$	110.9	$	17.0

Regulated Gas Sales (Bcf)	2005		2004		Change

Residential		5.5		5.7		(.2	)
Commercial		3.4		3.4		-
Industrial		.5		.6		(.1	)
Transportation and Other		3.1		3.4		(.3	)
Total Regulated Gas Sales		12.5		13.1		(.6	)

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Regulated Gas Customers (000s)	2005		2004		Change

Residential		109		108		1
Commercial		9		9		-
Industrial		-		-		-
Transportation and Other		-		-		-
Total Regulated Gas Customers		118		117		1

Regulated Gas Revenue increased $17.0 million primarily due to a $17.9 million increase, effective November 1, 2004, in the Gas Cost Rate due to higher natural gas commodity costs (offset in Gas Purchased).

Other Gas Revenue decreased by $7.0 million largely due to significantly fewer off-system sales compared to the same period last year partially offset by increased capacity release volumes (offset in Gas Purchased).

Competitive Energy Business

The following table divides the operating revenues of the Competitive Energy business among its major business activities.

	2005		2004		Change

Merchant Generation	$	243.5	$	231.8	$	11.7
Requirements Load Service (POLR, BGS, SOS)		381.1		548.9		(167.8	)
Oil & Gas Marketing Services and Other		469.0		372.5		96.5
Total Conectiv Energy Operating Revenue	$	1,093.6	$	1,153.2	$	(59.6	)

Pepco Energy Services	$	672.8	$	554.2	$	118.6

·	Merchant Generation experienced an increase of $11.7 million primarily due to increased power prices (approximately 13% higher).
·	Requirements Load Service experienced a decrease of $167.8 million due to a decrease in DPL's POLR load of 33% because of the implementation of competitive bidding on wholesale supply in Maryland and Virginia, and lower New Jersey BGS sales of 30%. Many of Conectiv Energy's 12-month New Jersey BGS supply contracts ended in the middle of 2004. Conectiv Energy won fewer bids on BGS load for the 2004-2005 period in the 2004 BGS auction.
·	Oil and Gas Marketing Services and Other increased by $96.5 million primarily due to increased wholesale natural gas sales and higher natural gas prices.

The increase in Pepco Energy Services' operating revenue of $118.6 million is primarily due to increased commercial and industrial load acquisition by Pepco Energy Services in 2005 at somewhat higher prices than in the 2004 period. As of June 30, 2005, Pepco Energy Services had 2,540 megawatts of commercial and industrial load, as compared to 1,475 megawatts of commercial and industrial load at the end of the 2004 period.

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Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

A detail of PHI's consolidated fuel and purchased energy and other services cost of sales is as follows:

	2005			2004			Change
Power Delivery	$	1,221.5		$	1,225.2		$	(3.7	)
Conectiv Energy		981.7			1,033.3			(51.6	)
Pepco Energy Services		613.1			504.0			109.1
Other Non-Regulated		-			-			-
Corporate and Other		(367.7	)		(411.3	)		43.6
Total	$	2,448.6		$	2,351.2		$	97.4

Power Delivery's Fuel and Purchased Energy costs decreased by $3.7 million primarily due to the following: (i) $8.7 million lower energy costs, (offset in Default Electricity Supply Revenue), (ii) $6.0 million lower PJM network transmission costs, partially offset by (iii) $9.5 million for gas commodity fuel costs, and (iv) $3.1 million increase in costs due to the end of the generation procurement credit (GPC) as a result of the new SOS agreements.

The following table divides the fuel and purchased energy and other services costs of sales of the Competitive Energy business among its major business activities.

	2005		2004		Change

Merchant Generation	$	132.8	$	121.7	$	11.1
Requirements Load Service (POLR, BGS, SOS)		379.9		543.4		(163.5	)
Oil & Gas Marketing Services and Other		469.0		368.2		100.8
Total Conectiv Energy Fuel and Purchased Energy and Other Services Cost of Sales	$	981.7	$	1,033.3	$	(51.6	)

Pepco Energy Services	$	613.1	$	504.0	$	109.1

The decrease of $51.6 million in Conectiv Energy's fuel, purchased energy and other services cost of sales is attributable to the following:

·	Merchant Generation costs increased by $11.1 million mainly due to higher fuel costs.
·	Requirements Load Service costs decreased by $163.5 million due to a decrease in DPL's POLR load of 33% because of the implementation of competitive bidding on wholesale supply in Maryland and Virginia, and lower New Jersey BGS sales of 30%.
·	Oil and Gas Marketing Services and Other costs increased by $100.8 million primarily due to increased wholesale natural gas sales and higher natural gas prices.

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The increase in Pepco Energy Services' fuel and purchased energy and other services cost of sales of $109.1 million resulted from higher volumes of electricity purchased at higher prices in 2005 to serve customers.

Other Operation and Maintenance

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

	2005			2004			Change
Power Delivery	$	300.0		$	303.0		$	(3.0	)
Conectiv Energy		45.6			47.1			(1.5	)
Pepco Energy Services		34.2			34.7			(.5	)
Other Non-Regulated		2.8			3.9			(1.1	)
Corporate and Other		(3.3	)		(5.9	)		2.6
Total	$	379.3		$	382.8		$	(3.5	)

PHI's other operation and maintenance decreased by $3.5 million to $379.3 million in the 2005 six month period from $382.8 million in the 2004 six month period primarily due to $4.2 million lower PJM administrative expenses due to the implementation of market based SOS.

Depreciation and Amortization

PHI's depreciation and amortization expenses decreased by $14.7 million to $207.5 million in the 2005 six month period from $222.2 million in the 2004 six month period primarily due to (i) $6.5 million decrease in deferred transitional bond charges, (ii) $4.9 million decrease related to the disposition of non-regulated assets and (iii) $2.6 million decrease due to software retirements.

Other Taxes

Other taxes increased by $21.9 million to $158.1 million in the 2005 six month period from $136.2 million in the 2004 six month period. This increase was primarily due to (i) $12.3 million increase attributable to higher county surcharge rate increase (offset in Regulated T& D Electric Revenue), (ii) $5.3 million related to property tax accruals and (iii) $1.6 million related to NJ excise tax accrual.

Deferred Electric Service Costs

DESC decreased by $8.2 million to $.8 million for the six months ended June 30, 2005 from $9.0 million for the six months ended June 30, 2004. The $8.2 million decrease represents (i) $13.8 million net under-recovery associated with New Jersey BGS, NUGs, market transition charges and other restructuring items partially offset by (ii) $4.5 million in regulatory disallowances (net of amounts previously reserved) associated with the April 2005 NJBPU settlement agreement and (iii) $1.1 million in deferral write-offs associated with the NJBPU settlement agreement. On ACE's balance sheet a regulatory asset includes an under-recovery of $96.8 million as of June 30, 2005. This amount is net of a $47.3 million reserve on previously disallowed items under appeal.

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Gain on Sale of Assets

PHI's gain on sale of assets in 2005 primarily represents a $2.8 million gain from the sale of Pepco land. The gain in 2004 consists primarily of a $14.4 million gain from the condemnation settlement with the City of Vineland, New Jersey relating to the transfer of ACE's distribution assets and customer accounts to the city during the second quarter of 2004. Additionally, during the first quarter of 2004, PHI recorded a $6.6 million gain on the sale of land and a $5.5 million gain on the sale of two aircraft, which reduced operating expenses.

Other Income (Expenses)

PHI's other expense (which is net of other income) decreased $27.0 million to $140.8 million in the 2005 six month period, from $167.8 million in the 2004 six month period primarily due to the following: (i) a reduction in net interest expense of $14.1 million mainly due to lower debt outstanding, (ii) an $11.2 million impairment charge on the Starpower investment that was recorded during the second quarter of 2004, (iii) income of $7.9 million received by PCI from the sale and liquidation of energy investments, and (iv) $4.6 million increase in other income, partially offset by (v) a pre-tax gain of $11.2 million on a distribution from a co-generation joint-venture that was recognized by Conectiv Energy during the second quarter of 2004.

Income Tax Expense

Extraordinary Item

On April 19, 2005, a settlement of ACE's electric distribution rate case was reached among ACE, the staff of the NJBPU, the New Jersey Ratepayer Advocate, and active intervenor parties. As a result of the settlement ACE reversed $15.2 million ($9.0 million, after-tax) in accruals related to certain deferred costs that are now deemed recoverable.

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CAPITAL RESOURCES AND LIQUIDITY

Capital Structure

The components of Pepco Holdings' capital structure, expressed as a percentage of total capitalization (including short-term debt and current maturities of long-term debt but excluding (i) transition bonds issued by Atlantic City Electric Transition Funding LLC (ACE Funding) in the principal amount of $537.8 million and $551.3 million at June 30, 2005 and December 31, 2004, respectively, and (ii) Pepco Energy Services' project funding secured by customer accounts receivable of $79.5 million and $70.7 million at June 30, 2005 and December 31, 2004, respectively) are shown below. The transition bonds issued by ACE Funding and the project funding of Pepco Energy Services, which are both effectively securitized, are excluded because the major credit rating agencies treat effectively securitized debt separately and not as general obligations of PHI, when computing credit quality measures. (Dollar amounts in the table are in millions.)

		June 30, 2005					December 31, 2004
Common Shareholders' Equity	$	3,424.9		39.1	%	$	3,366.3	39.2	%
Preferred Stock of subsidiaries (a)		54.9		.6			54.9	.6
Long-Term Debt (b)		5,111.6	(c)	58.4			5,003.3	58.3
Short-Term Debt (d)		167.2		1.9			161.3	1.9
Total	$	8,758.6		100.0	%	$	8,585.8	100.0	%

(a)	Consists of Serial Preferred Stock and Redeemable Serial Preferred Stock issued by subsidiaries of PHI.
(b)	Consists of first mortgage bonds, medium term notes, other long-term debt, current maturities of long-term debt, and Variable Rate Demand Bonds. Excludes capital lease obligations, transition bonds issued by ACE Funding, and project funding of Pepco Energy Services secured by customer accounts receivable.
(c)	Includes $175 million of Senior Notes issued by Pepco in June. The proceeds are included in Cash and Cash Equivalents on the Balance Sheet of PHI at June 30, 2005, and will be used to redeem $175 million of Pepco's first mortgage bonds in September 2005.
(d)	Excludes current maturities of long-term debt, capital lease obligations due within one year, and Variable Rate Demand Bonds (VRDB). In accordance with GAAP, the VRDB are included in short-term debt on the Balance Sheet of PHI because they are due on demand by the bondholder. Bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis and the remarketing resets the interest rate at market rates. However, PHI views the VRDBs as long-term financing in effect because the maturity dates range from 2009 to 2031, and PHI expects the remarketing to be successful due to the creditworthiness of the issuers.

Financing Activity During the Three Months Ended June 30, 2005

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In June 2005, DPL issued $100 million of 5.0% unsecured notes due 2015. The net proceeds were used to redeem $100 million of DPL's 7.71% first mortgage bonds due 2025.

In June 2005, DPL made a sinking fund payment of $2.7 million on its 6.95% first mortgage bonds due 2008.

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In June 2005, Pepco Holdings issued $250 million of floating rate unsecured notes due 2010. The net proceeds were used to repay commercial paper issued to fund the redemptions of Conectiv debt.

Financing Activity Subsequent to June 30, 2005

In July 2005, ACE retired at maturity $20.3 million of medium-term notes with a weighted average interest rate of 6.37%.

In July 2005, ACE Funding made principal payments of $4.5 million of Series 2002-1 Bonds, Class A-1 and $1.6 million Series 2003-1 Bonds, Class A-1 with a weighted average interest rate of 2.89%.

In August 2005, ACE retired at maturity $2 million of 6.38% medium-term notes.

Sale of Buzzard Point Property

IRS Revenue Ruling

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and deferred income tax balances, but would not affect earnings, other than a charge for the accrual of related interest.

Working Capital

At June 30, 2005, PHI's current assets on a consolidated basis totaled $1.9 billion and its current liabilities totaled $2.1 billion. At December 31, 2004, PHI's current assets on a consolidated basis totaled $1.7 billion and its current liabilities totaled $2.0 billion.

PHI's working capital deficit results in large part from the fact that, in the normal course of business, PHI's utility subsidiaries acquire and pay for energy supplies for their customers before the supplies are metered and then billed to customers. Short-term financings are used to meet liquidity needs. Short-term financings are also used, at times, to temporarily fund redemptions of long-term debt, until long-term replacement financing is completed.

A detail of Pepco Holdings' short-term debt at June 30, 2005, in millions, is as follows:

	As of June 30, 2005
Type		PHI Parent		Pepco		DPL		ACE		ACE Funding		PES		PCI		PHI Consolidated
Variable Rate Demand Bonds	$	-	$	-	$	104.8	$	22.6	$	-	$	31.0	$	-	$	158.4
Current Portion of Long-Term Debt		300.0		175.0		2.9		93.0		28.3		.1		60.0		659.3
Current Portion of Project Funding Secured by Accounts Receivable		-		-		-		-		-		6.2		-		6.2
Floating Rate Note		50.0		-		-		-		-		-		-		50.0
Commercial Paper		-		-		-		117.2		-		-		-		117.2
Total	$	350.0	$	175.0	$	107.7	$	232.8	$	28.3	$	37.3	$	60.0	$	991.1

Cash Flow Activity

PHI's cash flows for the six months ended June 30, 2005 and 2004 are summarized below.

	Cash Source / (Use)
		2005			2004
		(Dollars in Millions)
Operating activities	$	305.9		$	245.6
Investing activities		(179.4	)		(189.3	)
Financing activities		21.0			(101.4	)
Net increase (decrease) in cash and cash equivalents	$	147.5		$	(45.1	)

Operating Activities

Cash flows from operating activities during the six months ended June 30, 2005 and 2004 are summarized below.

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	Cash Source / (Use)
		2005		2004
		(Dollars in Millions)
Net income	$	119.5	$	141.6
Non-cash adjustments to net income		181.3		222.7
Changes in working capital		5.1		(118.7	)
Net cash from operating activities	$	305.9	$	245.6

Net cash provided by operating activities increased $60.3 million for the six months ended June 30, 2005 compared to the same period in 2004. The change is primarily due to (i) a $50.7 million decrease in the cash flows used by changes in accounts receivable as a result of milder weather experienced in 2005 compared to 2004 and (ii) a $12 million decrease in interest paid on long-term debt for the six months ended 2005 in comparison to the same period in 2004, partially offset by property and right-of-way tax payments made in 2005.

Investing Activities

Cash flows from investing activities during the six months ended June 30, 2005 and 2004 are summarized below.

	Cash Source / (Use)
		2005			2004
		(Dollars in Millions)
Construction expenditures	$	(218.2	)	$	(233.2	)
Cash proceeds from sale of:
Other investments		23.8			15.1
Marketable securities, net		-			19.4
Office building and other properties		4.6			39.8
All other investing cash flows, net		10.4			(30.4	)
Net cash used by investing activities	$	(179.4	)	$	(189.3	)

Net cash used by investing activities decreased by $9.9 million for the six months ended June 30, 2005 compared to the same period in 2004. The decrease was primarily due to lower construction expenditures by Power Delivery and higher proceeds from the sales of other investments in 2005, partially offset by asset sale proceeds during 2004 and from proceeds from the sale of marketable securities during 2004.

Financing Activities

Cash flows from financing activities during the six months ended June 30, 2005 and 2004 are summarized below.

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	Cash Source / (Use)
		2005			2004
		(Dollars in Millions)
Common and preferred stock dividends	$	(95.6	)	$	(87.4	)
Common stock issuances		14.0			15.0
Debenture redemptions		-			(95.0	)
Long-term debt issuances		533.7			395.0
Long-term debt redemptions		(428.3	)		(459.2	)
Short-term debt, net		5.9			143.0
All other financing cash flows, net		(8.7	)		(12.8	)
Net cash from (used by) financing activities	$	21.0		$	(101.4	)

In 2004, the debenture redemptions represent mandatorily redeemable trust preferred securities of $70 million for DPL and $25 million for ACE.

In 2004, Pepco issued $275 million and ACE issued $120 million of secured senior notes. Proceeds were used to redeem higher rate securities and to repay short-term debt.

In 2005, Pepco issued $175 million of senior secured notes due 2035. The net proceeds will be used to redeem higher rate securities in September 2005.

In 2005, DPL issued $100 million of unsecured notes due 2015 to redeem higher rate securities.

In 2005, Pepco Holdings issued $250 million of floating rate unsecured notes due 2010. The net proceeds were used to repay commercial paper issued to fund the redemptions of Conectiv debt.

In 2004, net short-term debt issuances were higher primarily due to ACE's short-term borrowing needs for the redemptions of long-term debt and trust preferred securities, higher construction expenditures and a common stock repurchase.

Capital Requirements

Construction Expenditures

Pepco Holdings' construction expenditures for the six months ended June 30, 2005 totaled $218.2 million of which $207.1 million was related to its Power Delivery businesses. The remainder was primarily related to Conectiv Energy. The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability, and transmission.

Third Party Guarantees, Indemnifications and Off-Balance Sheet Arrangements

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	Guarantor
		PHI		DPL		ACE		Other		Total
Energy marketing obligations of Conectiv Energy (1)	$	154.0	$	-	$	-	$	-	$	154.0
Energy procurement obligations ofPepco Energy Services (1)		6.9		-		-		-		6.9
Standby letters of credit of Pepco Holdings (2)		.5		-		-		-		.5
Guaranteed lease residual values (3)		.4		3.2		3.0		.3		6.9
Loan agreement (4)		13.1		-		-		-		13.1
Other (5)		19.0		-		-		2.7		21.7
Total	$	193.9	$	3.2	$	3.0	$	3.0	$	203.1

1.	Pepco Holdings has contractual commitments for performance and related payments of Conectiv Energy and Pepco Energy Services to counterparties related to routine energy sales and procurement obligations, including requirements under BGS contracts entered into with ACE.
2.	Pepco Holdings has issued standby letters of credit of $.5 million on behalf of subsidiaries' operations related to Conectiv Energy's competitive energy activities and third party construction performance. These standby letters of credit were put into place in order to allow the subsidiaries the flexibility needed to conduct business with counterparties without having to post substantial cash collateral. While the exposure under these standby letters of credit is $.5 million, Pepco Holdings does not expect to fund the full amount.
3.	Subsidiaries of Pepco Holdings have guaranteed residual values in excess of fair value related to certain equipment and fleet vehicles held through lease agreements. As of June 30, 2005, obligations under the guarantees were approximately $6.9 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.
4.	Pepco Holdings has issued a guarantee on the behalf of a subsidiary's 50% unconsolidated investment in a limited liability company for repayment borrowings under a loan agreement of approximately $13.1 million.
5.	Other guarantees consist of:
	·	Pepco Holdings has performance obligations of $.5 million relating to obligations to third party suppliers of equipment.

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	·	Pepco Holdings has guaranteed payment of a bond issued by a subsidiary of $14.9 million. Pepco Holdings does not expect to fund the full amount of the exposure under the guarantee.
	·	Pepco Holdings has guaranteed a subsidiary building lease of $3.6 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. As of June 30, 2005, the guarantees cover the remaining $2.7 million in rental obligations.

Dividends

On June 30, 2005, Pepco Holdings paid a dividend on its common stock of 25 cents per share to shareholders of record on June 10, 2005. On July 28, 2005, Pepco Holdings' Board of Directors declared a dividend on common stock of 25 cents per share payable September 30, 2005, to shareholders of record on September 10, 2005.

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Energy Contract Net Asset Activity

The following table provides detail on changes in the competitive energy segments' net asset or liability position with respect to energy commodity contracts from one period to the next:

Roll-forward of Mark-to-Market Energy Contract Net Assets For the Six Months Ended June 30, 2005 (Dollars are Pre-Tax and in Millions)
	ProprietaryTrading(1)	Other EnergyCommodity(2)	Total
Total Marked-to-Market (MTM) Energy Contract Net Assets at December 31, 2004	$ .9	$ 25.7	$ 26.6
Total change in unrealized fair value excluding reclassification to realized at settlement of contracts	.1	8.2	8.3
Reclassification to realized at settlement of contracts	(.5)	(36.2)	(36.7)
Effective portion of changes in fair value - recorded in OCI	-	29.0	29.0
Ineffective portion of changes in fair value - recorded in earnings	-	1.5	1.5
Changes in valuation techniques and assumptions	-	-	-
Purchase/sale of existing contracts or portfolios subject to MTM	-	-	-
Total MTM Energy Contract Net Assets at June 30, 2005 (a)	$ .5 (3)	$ 28.2	$ 28.7

(a) Detail of MTM Energy Contract Net Assets at June 30, 2005 (above)			Total
Current Assets			$ 69.9
Noncurrent Assets			54.3
Total MTM Energy Assets			124.2
Current Liabilities			(20.8)
Noncurrent Liabilities			(74.7)
Total MTM Energy Contract Liabilities			(95.5)
Total MTM Energy Contract Net Assets			$ 28.7

Notes:
(1)	The forward value of the trading contracts represents positions held prior to the cessation of proprietary trading. The values were locked in during the exit from trading and will be realized during the normal course of business through the end of 2005.
(2)	Includes all SFAS 133 hedge activity and non-proprietary trading activities marked-to-market through earnings.
(3)	This amount will not be materially sensitive to commodity price movements because it represents positions that have been volumetrically offset almost 100% since the first quarter of 2003.

The following table provides the source of fair value information (exchange-traded, provided by other external sources, or modeled internally) used to determine the carrying amount of the competitive energy segments' total mark-to-market energy contract net assets. The table also provides the maturity, by year, of the competitive energy segments' mark-to-market energy contract net assets, which indicates when the amounts will settle and either generate cash for, or require payment of cash by, PHI.

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PHI uses its best estimates to determine the fair value of the commodity and derivative contracts that its competitive energy segments hold and sell. The fair values in each category presented below reflect forward prices and volatility factors as of June 30, 2005 and are subject to change as a result of changes in these factors:

Maturity and Source of Fair Value of Mark-to-Market Energy Contract Net Assets As of June 30, 2005 (Dollars are Pre-Tax and in Millions)
	Fair Value of Contracts at June 30, 2005
	Maturities
Source of Fair Value	2005	2006	2007	2008 and Beyond	Total Fair Value
Proprietary Trading (1)
Actively Quoted (i.e., exchange-traded) prices (1)	$ .5	$ -	$ -	$ -	$ .5
Prices provided by other external sources (2)	-	-	-	-	-
Modeled	-	-	-	-	-
Total	$ .5	$ -	$ -	$ -	$ .5
Other Energy Commodity (3)
Actively Quoted (i.e., exchange-traded) prices	$19.1	$17.9	$13.1	$ .7	$50.8
Prices provided by other external sources (2)	(4.1)	(45.2)	(18.0)	(2.0)	(69.3)
Modeled (4)	15.5	31.2	-	-	46.7
Total	$30.5	$ 3.9	$(4.9)	$(1.3)	$28.2

Notes:
(1)	The forward value of the trading contracts represents positions held prior to the cessation of proprietary trading. The values were locked in during the exit from trading and will be realized during the normal course of business through the end of 2005.
(2)	Prices provided by other external sources reflect information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(3)	Includes all SFAS No. 133 hedge activity and non-trading activities marked-to-market through AOCI or on the Income Statement as required.
(4)	The modeled hedge position is a power swap for 50% of Conectiv Energy's obligation to supply POLR to DPL. The model is used to approximate the forward load quantities. Pricing is derived from the broker market.

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Contractual Arrangements with Credit Rating Triggers or Margining Rights

Under certain contractual arrangements entered into by PHI's subsidiaries in connection with competitive energy and other transactions, the affected company may be required to provide cash collateral or letters of credit as security for its contractual obligations if the credit rating for long-term unsecured debt of the applicable company is downgraded one or more levels. 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. As of June 30, 2005, a one-level downgrade in the credit rating of long-term unsecured debt of PHI and all of its affected subsidiaries would have required PHI and such subsidiaries to provide aggregate cash collateral or letters of credit of approximately up to $157.0 million. An additional amount of approximately $202.0 million of aggregate cash collateral or letters of credit would have been required in the event of subsequent downgrades t o below investment grade.

Many of the contractual arrangements entered into by PHI's subsidiaries in connection with competitive energy 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 that are 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, 2005, Pepco Holdings' subsidiaries that engaged in competitive energy activities were in receipt of (a net holder of) cash collateral in the amount of $6.6 million as recorded in connection with their competitive energy activities.

REGULATORY AND OTHER MATTERS

Relationship with Mirant Corporation

Transition Power Agreements

As part of the Asset Purchase and Sale Agreement, Pepco and Mirant entered into Transition Power Agreements for Maryland and the District of Columbia, respectively (collectively, the

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TPAs). Under these agreements, Mirant was obligated to supply Pepco with all of the capacity and energy needed to fulfill its SOS obligations in Maryland through June 2004 and its SOS obligations in the District of Columbia through January 22, 2005.

Power Purchase Agreements

Pepco Pre-Petition Claims

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Mirant debtors in respect of the Pepco TPA Claim. In view of the uncertainty as to recoverability, Pepco, in the third quarter of 2003, expensed $14.5 million to establish a reserve against the $29 million receivable from Mirant. In January 2004, Pepco paid approximately $2.5 million to Panda in settlement of certain billing disputes under the Panda PPA that related to periods after the sale of Pepco's generation assets to Mirant. Pepco believes that under the terms of the Asset Purchase and Sale Agreement, Mirant is obligated to reimburse Pepco for the settlement payment. Accordingly, in the first quarter of 2004, Pepco increased the amount of the receivable due from Mirant by approximately $2.5 million and amended its Proofs of Claim to include this amount. Pepco currently estimates that the $14.5 million expensed in the third quarter of 2003 represents the portion of the entire $31.5 million receivable unlikely to be recovered in bankruptcy, and no additional reserve has been established for the $2 .5 million increase in the receivable. The amount expensed represents Pepco's estimate of the possible outcome in bankruptcy, although the amount ultimately recovered could be higher or lower.

Mirant's Attempt to Reject the PPA-Related Obligations

On January 21, 2005, Mirant filed in the Bankruptcy Court a motion seeking to reject certain of its ongoing obligations under the Asset Purchase and Sale Agreement, including the PPA-

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Related Obligations (the Second Motion to Reject). On March 1, 2005, the District Court entered an order (which was amended on March 7, 2005) granting Pepco's motion to withdraw jurisdiction over the Asset Purchase and Sale Agreement rejection proceedings from the Bankruptcy Court. On March 28, 2005, Pepco, the Federal Energy Regulatory Commission (FERC), the Office of People's Counsel (OPC) of the District of Columbia, the Maryland Public Service Commission (MPSC) and the Maryland OPC filed oppositions to the Second Motion to Reject in the District Court. On July 15, 2005, Mirant filed a supplemental brief with the District Court in support of its Second Motion to Reject, addressing a June 17, 2005 FERC order (discussed below under "Mirant Plan of Reorganization"). Pepco's response to Mirant's supplemental brief was filed on July 22, 2005. The District Court has not yet set a hearing date regarding the Second Motion to Reject.

Any repayment by Pepco of amounts paid by Mirant would entitle Pepco to file a claim against the bankruptcy estate in an amount equal to the amount repaid. Pepco believes that, to the extent such amounts were not recovered from the Mirant bankruptcy estate; they would be recoverable as stranded costs from customers through distribution rates as described below.

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estimates assume no recovery from the Mirant bankruptcy estate and no regulatory recovery, either of which would mitigate the effect of the estimated loss. Pepco does not consider it realistic to assume that there will be no such recoveries. Based on these assumptions, Pepco estimates that its pre-tax exposure as of August 1, 2005 representing the loss of the future benefit of the PPA-Related Obligations to Pepco, is as follows:

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Mirant's Fraudulent Transfer Claim

The SMECO Agreement

Mirant Plan of Reorganization

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abandoned the proposal that the PPA-Related Obligations would remain in "Old Mirant," but did not clarify how the PPA-Related Obligations would be treated.

Rate Proceedings

New Jersey

For a discussion of the history of ACE's proceeding filed with the New Jersey Board of Public Utilities (NJBPU) to increase its electric distribution rates and Regulatory Asset Recovery Charge (RARC) in New Jersey (also referred to as Phase I) and a related Phase II proceeding, please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Rate Proceedings" of PHI's Annual Report on Form 10-K for the year ended December 31, 2004 (the PHI 2004 10-K) and Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Rate Proceedings" of PHI's Quarterly Report on Form 10-Q for the Quarter ended March 31, 2005 (the PHI 2005 First Quarter 10-Q). On April 19, 2005, a settlement was reached among ACE, the staff of the NJBPU, the New Jersey Ratepayer Advocate and active intervenor parties that resolved issues in both the Phase&nbs p;I and Phase II proceedings. The NJBPU approved this settlement in an order dated May 26, 2005.

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calculated excess or deficiencies in the depreciation reserve. As a result of these changes, PHI and ACE each had a net excess depreciation reserve. Accordingly, PHI and ACE each recorded a regulatory liability in March 2005 by reducing its depreciation reserve by approximately $131 million. The regulatory liability will be amortized over 8.25 years and will result in a reduction of depreciation and amortization expense on PHI's and ACE's consolidated statements of earnings. While the impact of the settlement is essentially revenue and cash neutral to PHI and ACE, there is a positive annual pre-tax earnings impact to PHI and ACE of approximately $20 million.

The settlement does not affect the existing appeal filed by ACE with the Appellate Division of the Superior Court of New Jersey related to the July 2004 Final Decision and Order issued by the NJBPU in ACE's restructuring deferral proceeding before the NJBPU under the New Jersey Electric Discount and Energy Competition Act. For additional information about this appeal and the New Jersey regulatory proceeding leading up to this appeal, please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Restructuring Deferral" of the PHI 2004 10-K.

Delaware

For a discussion of the history DPL's annual Gas Cost Rate (GCR) filing, please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Rate Proceedings" of the PHI 2004 10-K and Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Rate Proceedings" of the PHI 2005 First Quarter 10-Q. On July 15, 2005, the Hearing Examiner released her written recommendation that the rates sought by DPL should be approved. A final order addressing both the November 1 and December 29 increases is expected in the third quarter of 2005.

Restructuring Deferral

For a discussion of the history of ACE's appeal filed with the Appellate Division of the Superior Court of New Jersey related to the July 2004 Final Decision and Order issued by the NJBPU in ACE's restructuring deferral proceeding before the NJBPU under the New Jersey Electric Discount and Energy Competition Act, and the New Jersey regulatory proceeding leading up to this appeal, please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Restructuring Deferral" of the PHI 2004 10-K. ACE's initial brief is due on August 18, 2005. Final reply briefs are due by October 10, 2005. ACE cannot predict the outcome of this appeal.

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SOS, Default Service and BGS Proceedings

Virginia

For a discussion of the history of DPL's Default Service proceedings in Virginia, please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- SOS and Default Service Proceedings" of the PHI 2004 10-K. As discussed in the PHI 2004 10-K, the parties to this proceeding entered into and filed, on March 4, 2005, a settlement resolving the issues in this proceeding and making the interim rates DPL had put into effect final, without any administrative charge or margin, but with the amount of the final rates being contingent only on possible future adjustment depending on the result of a related proceeding at FERC. The VSCC approved the settlement on March 25, 2005. However, in the VSCC proceeding addressing "Proposed Rules Governing Exemptions to Minimum Stay Requirements and Wires Charges," the VSCC staff recognized that DPL should be entitled to earn a reasonable margin related to hourly pricing customers because DPL has no hourly priced customers in Virginia. DPL continues to maintain that a margin should be earned on all customer classes. DPL cannot predict the outcome of this proceeding.

For a discussion of the history of Conectiv Energy's filing with FERC requesting authorization to enter into a contract to supply power to DPL, please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- SOS and Default Service Proceedings" of the PHI 2004 10-K. On June 8, 2005, Conectiv Energy entered into a stipulation with FERC staff and the Virginia Office of Attorney General resolving all issues regarding DPL's procurement process. The stipulation concludes that DPL did not favor Conectiv Energy in awarding it the 2005 Supply Agreement. As part of the stipulation, DPL sent a letter to FERC committing to use a third-party independent monitor in future Virginia solicitations. The Administrative Law Judge (ALJ) has certified the stipulation to FERC. DPL cannot predict what action FERC will take with respect to the stipulation and ALJ certification.

Delaware

For a discussion of the history of DPL's SOS proceedings in Delaware, please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- SOS and Default Service Proceedings" of the PHI 2004 10-K. On July 18, 2005, the Delaware Public Service Commission (DPSC) staff, the Division of the Public Advocate, the group representing DPL's industrial and commercial customers, Conectiv Energy and DPL filed with the Hearing Examiner a comprehensive settlement agreement covering all Stage 2 issues described above. The agreement calls for DPL to provide SOS to all classes, with no specified termination date for SOS. Two categories of SOS will exist: (i) a fixed price SOS available to all but the largest customers; and (ii) an Hourly Priced Service (HPS) for the largest customers, HPS being mandatory for General Service - Transmission voltage (GS-T) customers and offered as an option for General Service - Pr imary voltage (GS-P) customers. If approved, a competitive bid process will be used to procure the full requirements of customers eligible for a fixed-price SOS. In addition to the costs of capacity, energy, transmission, and ancillary services associated with the fixed-price SOS and HPS, DPL's initial rates would include a component referred to as the Reasonable Allowance for Retail Margin (RARM). Components of the RARM would include estimated incremental expenses, a $2.75 million return, a cash working capital allowance, and recovery with a return over 5 years of the

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capitalized costs of a billing system to be used for billing HPS customers. The $2.75 million return would be recovered through a 0.6 mill charge per kilowatt hour to the fixed-price SOS customers and flat, non-bypassable charges of $400 per month for GS-T customers and $150 per month for GS-P customers who elected the HPS form of SOS. All such costs are presumed by DPL to be recoverable, but are subject to audit; furthermore, no settlement can override the statutory requirement that costs not be the product of waste, bad faith or an abuse of discretion. The settlement proposes that there will be a true-up proceeding during the second year to establish SOS and HPS rates based on the year-one actual costs, quantities of SOS and HPS provided, and the amount of actual recovery on the $2.75 million return. After year two, the only elements of rates that would be trued-up are the differences between the billed retail rates and the costs paid to the winning bidders in competitive SOS proceedings. Parties, including DPL, would be permitted to initiate a proceeding with the DPSC to adjust rates prospectively to reflect changes in incremental costs or quantities sold.

In testimony filed on July 29, 2005, the settlement was contested by the intervenors in the case that did not sign the settlement agreement. A public hearing was held on August 1 and a formal evidentiary hearing before a Hearing Examiner was held on August 4, 2005. The procedural schedule currently provides for DPSC deliberations by late September 2005, with a written order in October. Potential modifications to the settlement are also being discussed with the contesting parties. DPL cannot predict the outcome of this proceeding.

New Jersey

ACE Auction of Generation Assets

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Environmental Litigation

For a discussion of the history of DPL's de minimis consent decree with the United States in connection with DPL's alleged liability under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 at the Diamond State Salvage site in Wilmington, Delaware, please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Environmental Litigation" of the PHI 2004 10-K. The U.S. District Court approved the de minimis consent decree on June 24, 2005.

Preliminary Settlement Agreement with the NJDEP

For a discussion of the history and details of the April 26, 2004 preliminary settlement agreement entered into by PHI, Conectiv, ACE, the New Jersey Department of Environmental Protection (NJDEP) and the Attorney General of New Jersey, please refer to "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Preliminary Settlement Agreement with the NJDEP" of the PHI 2004 10-K and "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Preliminary Settlement Agreement with the NJDEP" of the PHI 2005 First Quarter 10-Q. As discussed in the PHI 2004 10-K, under the preliminary settlement agreement, in order to address ACE's appeal of NJDEP actions relating to NJDEP's July 2001 denial of ACE's request to renew a permit variance from sulfur-in-fuel requirements under New Jersey regulations, effective through July 30, 2001, that authorized Unit 1 at B.L. England generating facility to burn bituminous coal containing greater than 1% sulfur, ACE will be permitted to combust coal with a sulfur content of greater than 1% at the B.L. England facility in accordance with the terms of B.L. England's current permit until December 15, 2007 and NJDEP will not impose new, more stringent short-term SO2 emissions limits on the B.L. England facility during this period. By letter dated July 13, 2005, NJDEP extended, until October 30, 2005, the deadline for ACE to file an application to renew its current fuel authorization for the B.L. England generating plant, which is scheduled to expire on July 30, 2006.

Federal Tax Treatment of Cross-Border Leases

For a discussion of the history and details of the issues related to federal tax treatment of PCI's portfolio of cross-border energy sale-leaseback transactions, please refer to "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Federal Tax Treatment of Cross-Border Leases" of the PHI 2004 10-K and "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Federal Tax Treatment of Cross-Border Leases " of the 2005 First Quarter 10-Q. On June 29, 2005 the Internal Revenue Service (IRS) published a Coordinated Issue Paper with respect to such transactions. PCI's cross-border energy leases are similar to those sale-leaseback transactions described in the Notice and the Coordinated Issue Paper.

In July 2005, the Financial Accounting Standards Board (FASB) released a Proposed Staff position that would amend SFAS No. 13 and require a lease to be repriced and the book value adjusted when there is a change or probable change in the timing of tax benefits. Under this proposal, a material change in the timing of cash flows under PCI's cross-border leases as the

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result of a settlement with the IRS also would require an adjustment to the book value. If adopted, the application of this guidance could result in a material adverse effect on PHI's results of operations even if a resolution with the IRS is limited to a deferral of the tax benefits realized by PCI from its leases.

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 of Pepco Holdings' Annual Report on Form 10-K for the year ended December 31, 2004. During the second quarter of 2005, Pepco Holdings identified the following as an additional critical accounting policy.

Unbilled Revenue

Unbilled revenue represents an estimate of revenue earned from services rendered by Pepco Holding's utility operations that have not yet been billed. Pepco Holdings utility operations calculate unbilled revenue using an output based methodology. (This methodology is based on the supply of electricity or gas distributed to customers.) Pepco Holdings believes that the estimates involved in its unbilled revenue process represent "Critical Accounting Estimates" because management is required to make assumptions and judgments about input factors such as customer sales mix, and estimated power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers), which are all inherently uncertain and susceptible to change from period to period, the impact of which could be material.

NEW ACCOUNTING STANDARDS

SFAS No. 154

In May 2005, the FASB issued Statement No. 154, "Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3" (SFAS No. 154).SFAS No. 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. The reporting of a correction of an error by restating previously issued financial statements is also addressed by SFAS No. 154. This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Early adoption is permitted.

SAB 107 and SFAS 123R

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(i.e., the year ended December 31, 2006 for Pepco Holdings). Pepco Holdings is in the process of completing its evaluation of the impact of SFAS 123R and does not anticipate that its implementation or SAB 107 will have a material effect on PHI's overall financial condition or results of operations.

FIN 47

RISK FACTORS

The businesses of PHI and its subsidiaries are subject to numerous risks and uncertainties. The occurrence of one or more of these events or conditions could have an adverse effect on the business of PHI and its subsidiaries, including, depending on the circumstances, their results of operations and financial condition. For a discussion of these risk factors, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations of Pepco Holdings' Annual Report on Form 10-K for the year ended December 31, 2004. Set forth below is an update of one of those risk factors.

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.

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In addition, a disallowance, rather than a deferral, of tax benefits to be realized by PHI from these leases will require PHI to adjust the book value of its leases and record a charge to earnings equal to the repricing impact of the disallowed deductions. Such a change would likely have a material adverse effect on PHI's results of operations for the period in which the charge is recorded. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Regulatory and Other Matters."

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 our or our industry's ac tual 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 with respect to 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;

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·	Changes in project costs;
·	Unanticipated changes in operating expenses and capital expenditures;
·	The ability to obtain funding in the capital markets on favorable terms;
·	Restrictions imposed by PUHCA;
·	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 market concerns; 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 of such factors, nor can Pepco Holdings assess the impact of any such factors on its 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. Additionally, Pepco provides Standard Offer Service, 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. Pepco's service territory covers approximately 640 square miles and has a population of approximately2 million.As of June 30, 2005, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to Washington, D.C. customers.

Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (PHI or Pepco Holdings). Because PHI is a public utility holding company registered under the Public Utility Holding Company Act of 1935 (PUHCA), the relationship between PHI and Pepco and certain activities of Pepco are subject to the regulatory oversight of the Securities and Exchange Commission under PUHCA.

RESULTS OF OPERATIONS

Operating Revenue

	2005		2004		Change
Regulated T&D Electric Revenue	$	202.0	$	212.1	$	(10.1	)
Default Supply Revenue		187.5		239.7		(52.2	)
Other Electric Revenue		6.6		9.4		(2.8	)
Total Operating Revenue	$	396.1	$	461.2	$	(65.1	)

The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated T&D (Transmission and Distribution) Electric Revenue and Default Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue). Regulated T&D Electric Revenue consists of the revenue Pepco receives for delivery of electricity to its customers for which service Pepco is paid regulated rates. Default Electricity Supply is also known as Standard Offer Service (SOS) in both the District of Columbia and Maryland. Default Supply Revenue is the revenue received from Default Electricity Supply. The costs related to the supply of electricity are included in Fuel and Purchased Energy. Other Electric Revenue includes work and services performed on behalf of customers including other utilities, which is not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rents, late payments , and collection fees.

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Regulated T&D Electric

Regulated T&D Electric Revenue	2005		2004		Change

Residential	$	57.8	$	62.6	$	(4.8	)
Commercial		115.6		121.0		(5.4	)
Industrial		-		-		-
Other (Includes PJM)		28.6		28.5		.1
Total Regulated T&D Electric Revenue	$	202.0	$	212.1	$	(10.1	)

Regulated T&D Electric Sales (GwH)	2005		2004		Change

Residential		1,679		1,908		(229	)
Commercial		4,356		4,739		(383	)
Industrial		-		-		-
Other		34		34		-
Total Regulated T&D Electric Sales		6,069		6,681		(612	)

Regulated T&D Electric Customers (000s)	2005		2004		Change

Residential		667		660		7
Commercial		74		72		2
Industrial		-		-		-
Other		-		-		-
Total Regulated T&D Electric Customers		741		732		9

Regulated T&D Electric Revenue decreased by $10.1 million due to the following: (i) $7.5 million related to Pepco's adjustment to correct the unbilled revenue amount that was reported in the first quarter of 2005, (ii) $7.2 million due to milder weather, the result of a 32% decrease in cooling degree days in 2005, offset by (iii) $3.5 million increase in tax pass-throughs, primarily a county surcharge rate increase (offset in Other Taxes) and (iv) $1.1 million increase related to changes in customer class mix. Delivery sales were approximately 6,069 GwH for the three months ended June 30, 2005, from approximately 6,681 GwH in the comparable period in 2004.

Default Electricity Supply

Default Supply Revenue	2005		2004		Change

Residential	$	98.6	$	92.6	$	6.0
Commercial		87.5		146.3		(58.8	)
Industrial		-		-		-
Other (Includes PJM)		1.4		.8		.6
Total Default Supply Revenue	$	187.5	$	239.7	$	(52.2	)

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Default Electricity Supply Sales (GwH)	2005		2004		Change

Residential		1,560		1,690		(130	)
Commercial		1,340		3,059		(1,719	)
Industrial		-		-		-
Other		21		29		(8	)
Total Default Electricity Supply Sales		2,921		4,778		(1,857	)

Default Electricity Supply Customers (000s)	2005		2004		Change

Residential		629		591		38
Commercial		59		61		(2	)
Industrial		-		-		-
Other		-		-		-
Total Default Electricity Supply Customers		688		652		36

Default Supply Revenue decreased by $52.2 million due to lower sales primarily driven by commercial customer migration as a result of market based SOS beginning in Maryland in July 2004 and in the District of Columbia in February 2005 (offset in Fuel and Purchased Energy).

For the three months ended June 30, 2005, Pepco's Maryland customers served by an alternate supplier represented 38% of Pepco's total Maryland load, and Pepco's District of Columbia customers served by an alternate supplier represented 71% of Pepco's total District of Columbia load. For the three months ended June 30, 2004, Pepco's Maryland customers served by an alternate supplier represented 21% of Pepco's total Maryland load, and Pepco's District of Columbia customers served by an alternate supplier represented 39% of Pepco's total District of Columbia load.

Default Electricity Supply Sales were approximately 2,921 GwH for the three months ended June 30, 2005, compared to approximately 4,778 GwH for the comparable period in 2004.

Operating Expenses

Fuel and Purchased Energy

Fuel and Purchased Energy decreased by $54.3 million to $179.0 million for the three months ended June 30, 2005, from $233.3 million for the comparable period in 2004. The decrease was due to the following: (i) $49.7 million lower energy costs (offset in Default Supply Revenue), (ii) $3.3 million lower PJM network transmission costs, and (iii) $1.3 million lower costs due to the end of the generation procurement credit (GPC) as a result of the new Default Electricity Supply agreements.

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Other Operation and Maintenance

Other Operation and Maintenance expenses increased by $1.4 million to $64.8 million for the three months ended June 30, 2005, from $63.4 million for the corresponding period in 2004. The increase was primarily due to the following: (i) $5.6 million higher employee benefit related costs, partially offset by (ii) $2.1 million lower PJM administrative expenses due to market based SOS and (iii) $1.2 million lower information technology costs.

Depreciation and Amortization

Depreciation and Amortization expenses decreased by $2.4 million to $39.8 million for the three months ended June 30, 2005 from $42.2 million for the comparable period in 2004. The decrease is primarily due to a decrease of $2.7 million related to the disposition of non-regulated assets.

Gain on Sale of Assets

This amount represents the gain of $2.8 million on Pepco's sale of land in the second quarter of 2005.

Other Income (Expenses)

Other Expenses decreased by $5.2 million to a net expense of $13.5 million for the three months ended June 30, 2005 from a net expense of $18.7 million for the comparable period in 2004. This was primarily due to $4.8 million higher other income, including $2.2 million from the sale of stock in 2005.

Income Tax Expense

Operating Revenue

	2005		2004		Change
Regulated T&D Electric Revenue	$	404.0	$	403.2	$	.8
Default Supply Revenue		402.0		408.9		(6.9	)
Other Electric Revenue		15.6		18.7		(3.1	)
Total Operating Revenue	$	821.6	$	830.8	$	(9.2	)

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Regulated T&D Electric

Regulated T&D Electric Revenue	2005		2004		Change

Residential	$	113.5	$	119.5	$	(6.0	)
Commercial		233.6		226.4		7.2
Industrial		-		-		-
Other (Includes PJM)		56.9		57.3		(.4	)
Total Regulated T&D Electric Revenue	$	404.0	$	403.2	$	.8

Regulated T&D Electric Sales (GwH)	2005		2004		Change

Residential		3,763		4,123		(360	)
Commercial		8,944		9,159		(215	)
Industrial		-		-		-
Other		79		80		(1	)
Total Regulated T&D Electric Sales		12,786		13,362		(576	)

Regulated T&D Electric Customers (000s)	2005		2004		Change

Residential		667		660		7
Commercial		74		72		2
Industrial		-		-		-
Other		-		-		-
Total Regulated T&D Electric Customers		741		732		9

Regulated T&D Electric Revenue increased by $.8 million due to the following: (i) $11.4 million increase in tax pass-throughs, primarily a county surcharge rate increase (offset in Other Taxes), partially offset by (ii) $8.1 million due to milder weather, the result of a 32% decrease in cooling degree days in 2005 and (iii) $2.5 million decrease due to changes in customer class mix. Delivery sales were approximately 12,786 GwH for the six months ended June 30, 2005, compared to approximately 13,362 GwH for the comparable period in 2004.

Default Electricity Supply

Default Supply Revenue	2005		2004		Change

Residential	$	205.2	$	166.2	$	39.0
Commercial		193.8		240.8		(47.0	)
Industrial		-		-		-
Other (Includes PJM)		3.0		1.9		1.1
Total Default Supply Revenue	$	402.0	$	408.9	$	(6.9	)

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Default Electricity Supply Sales (GwH)	2005		2004		Change

Residential		3,457		3,633		(176	)
Commercial		3,481		5,795		(2,314	)
Industrial		-		-		-
Other		49		66		(17	)
Total Default Electricity Supply Sales		6,987		9,494		(2,507	)

Default Electricity Supply Customers (000s)	2005		2004		Change

Residential		629		591		38
Commercial		59		61		(2	)
Industrial		-		-		-
Other		-		-		-
Total Default Electricity Supply Customers		688		652		36

Default Supply Revenue decreased $6.9 million due to lower sales driven by commercial customer migration as a result of market based SOS beginning in Maryland in July 2004 and in the District of Columbia in February 2005 (offset in Fuel and Purchased Energy).

For the six months ended June 30, 2005, Pepco's Maryland customers served by an alternate supplier represented 37% of Pepco's total Maryland load, and Pepco's District of Columbia customers served by an alternate supplier represented 62% of Pepco's total District of Columbia load. For the six months ended June 30, 2004, Pepco's Maryland customers served by an alternate supplier represented 23% of Pepco's total Maryland load, and Pepco's District of Columbia customers served by an alternate supplier represented 38% of Pepco's total District of Columbia load.

Default Electricity Supply Sales were approximately 6,987 GwH for the six months ended June 30, 2005, compared to approximately 9,494 GwH for the comparable period in 2004.

Operating Expenses

Fuel and Purchased Energy

Fuel and Purchased Energy decreased by $11.6 million to $395.4 million for the six months ended June 30, 2005, from $407.0 million for the comparable period in 2004. The decrease was due to the following: (i) $8.7 million lower energy costs, (offset in Default Supply Revenue), (ii) $6.0 million lower PJM network transmission costs, partially offset by (iii) $3.1 million increase in costs due to the end of the GPC as a result of the new SOS agreements.

Other Operation and Maintenance

Other Operation and Maintenance expenses increased by $.8 million to $131.3 million for the six months ended June 30, 2005, from $130.5 million for the corresponding period in 2004. The increase was primarily due to the following: (i) $6.5 million higher employee benefit related

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costs and (ii) $2.7 million higher building lease costs, partially offset by (iii) $4.2 million lower PJM administrative expenses and (iv) $3.0 million lower information technology costs.

Depreciation and Amortization

Depreciation and Amortization expenses decreased by $6.5 million to $79.6 million for the six months ended June 30, 2005 from $86.1 million for the comparable period in 2004. The decrease is primarily due to a decrease of $5.4 million related to the disposition of non-regulated assets and $1.7 million decrease due to software retirements.

Other Taxes

Other Taxes increased by $10.9 million to $126.1 million for the six months ended June 30, 2005, from $115.2 million for the comparable period in 2004. The increase was primarily due to pass-throughs of $12.3 million from a county surcharge rate increase (offset in Regulated T&D Electric Revenue), partially offset by $1.8 million lower property taxes primarily due to changes for the property tax accrual.

Gain on Sale of Assets

The 2005 amount represents Pepco's gain of $2.8 million on the sale of land during the second quarter. The amount in 2004 results from the gain of $6.6 million on the sale of land in the first quarter of 2004.

Other Income (Expenses)

Other Expenses decreased by $8.1 million to a net expense of $29.9 million for the six months ended June 30, 2005 from a net expense of $38.0 million for the comparable period in 2004. This was primarily due to: (i) $2.2 million from the sale of stock in 2005 and (ii) $1.5 million lower interest expense.

Income Tax Expense

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CAPITAL RESOURCES AND LIQUIDITY

Financing Activity During the Three Months Ended June 30, 2005

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Sale of Buzzard Point Property

IRS Revenue Ruling

During 2001, Pepco changed its methods of accounting with respect to capitalizable construction costs for income tax purposes, which allows Pepco to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through June 30, 2005, these accelerated deductions have generated approximately $119 million in tax cash flow benefits, primarily attributable to its 2001 tax returns. On August 2, 2005, the IRS issued Revenue Ruling 2005-53 (the Ruling) that will limit the ability of Pepco to utilize this method of accounting. Under the Ruling, Pepco may have to recapitalize and depreciate a portion of these expenses and repay a portion of the past income tax benefits, along with interest thereon.

Working Capital

At June 30, 2005, Pepco's current assets totaled $578.0 million and its current liabilities totaled $561.7 million. At December 31, 2004, Pepco's current assets totaled $364.0 million and its current liabilities totaled $434.6 million.

Pepco's working capital deficit at December 31, 2004 resulted in large part from the fact that, in the normal course of business, it acquires and pays for energy supplies for its customers before the supplies are metered and then billed to customers. Short-term financings are used to meet liquidity needs. Short-term financings are also used, at times, to temporarily fund redemptions of long-term debt, until long-term replacement issues are completed.

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Cash Flow Activities

Pepco's cash flows for the six months ended June 30, 2005 and 2004 are summarized below.

	Cash Source / (Use)
		2005			2004
		(Dollars in Millions)
Operating activities	$	123.1		$	84.3
Investing activities		(78.2	)		(74.4	)
Financing activities		141.3			(9.0	)
Net change in cash and cash equivalents	$	186.2		$	.9

Operating Activities

Cash flows from operating activities during the six months ended June 30, 2005 and 2004 are summarized below.

	Cash Source / (Use)
		2005		2004
		(Dollars in Millions)
Net income	$	35.4	$	35.6
Non-cash adjustments to net income		50.2		67.0
Changes in working capital		37.5		(18.3	)
Net cash provided by operating activities	$	123.1	$	84.3

Net cash flows provided by operating activities increased by $38.8 million to $123.1 million for the six months ended June 30, 2005 from $84.3 million for the comparable period in 2004. The increase was primarily due to increases in accounts receivable for the six months ended June 30, 2004 as a result of the unusually warm conditions experienced in May and June, partially offset by property and right-of-way tax payments made in 2005.

Investing Activities

Cash flows from investing activities during the six months ended June 30, 2005 and 2004 are summarized below.

	Cash Source / (Use)
		2005			2004
		(Dollars in Millions)
Construction expenditures	$	(81.3	)	$	(96.4	)
Cash proceeds from asset sales		2.8			22.0
All other investing cash flows, net		.3			-
Net cash used by investing activities	$	(78.2	)	$	(74.4	)

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Net cash used by investing activities increased by $3.8 million to $78.2 million for the six months ended June 30, 2005 from $74.4 million for the comparable period in 2004. The increase was primarily due to the receipt of proceeds from the sale of land in the first quarter of 2004, partially offset by a decrease in construction expenditures in 2005.

Financing Activities

Cash flows from financing activities during the six months ended June 30, 2005 and 2004 are summarized below.

	Cash Source / (Use)
		2005			2004
		(Dollars in Millions)
Dividends on common and preferred stock	$	(15.5	)	$	(43.0	)
Long-term debt, net		175.0			65.0
Short-term debt, net		(14.0	)		(22.0	)
All other financing cash flows, net		(4.2	)		(9.0	)
Net cash provided (used) by financing activities	$	141.3		$	(9.0	)

Net cash provided by financing activities increased by $150.3 million to $141.3 million for the six months ended June 30, 2005 from $(9.0) million for the comparable period in 2004. In the second quarter of 2005 Pepco issued $175 million of secured senior notes with maturities of 30 years; the proceeds of which are to be used to redeem higher interest rate securities in September 2005 and to repay short-term debt.

Capital Requirements

Construction Expenditures

Pepco's construction expenditures for the six months ended June 30, 2005 totaled $81.3 million. These expenditures were related to capital costs associated with new customer services, distribution reliability, and transmission.

REGULATORY AND OTHER MATTERS

Relationship with Mirant Corporation

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satisfy any additional cash requirements that may arise due to the Mirant bankruptcy. Accordingly, management does not anticipate that the Mirant bankruptcy will impair the ability of Pepco Holdings or Pepco to fulfill their contractual obligations or to fund projected capital expenditures. On this basis, management currently does not believe that the Mirant bankruptcy will have a material adverse effect on the financial condition of either company.

Transition Power Agreements

Power Purchase Agreements

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Pepco Pre-Petition Claims

Mirant's Attempt to Reject the PPA-Related Obligations

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that the amount it would be required to repay to Mirant on the disgorgement theory, in addition to the amounts described above, is approximately $22.5 million.

Any repayment by Pepco of amounts paid by Mirant would entitle Pepco to file a claim against the bankruptcy estate in an amount equal to the amount repaid. Pepco believes that, to the extent such amounts were not recovered from the Mirant bankruptcy estate; they would be recoverable as stranded costs from customers through distribution rates as described below.

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become assets of Pepco's distribution business if they could not be sold. Pepco believes that, if Mirant ultimately is successful in rejecting the PPA-Related Obligations, these provisions would allow the stranded costs of the PPAs that are not recovered from the Mirant bankruptcy estate to be recovered from Pepco's customers through its distribution rates. If Pepco's interpretation of the settlement agreements is confirmed, Pepco expects to be able to establish the amount of its anticipated recovery as a regulatory asset. However, there is no assurance that Pepco's interpretation of the settlement agreements would be confirmed by the respective public service commissions.

Mirant's Fraudulent Transfer Claim

The SMECO Agreement

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Mirant Plan of Reorganization

CRITICAL ACCOUNTING POLICIES

For a discussion of Pepco's critical accounting policies, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations of Pepco's Annual Report on Form 10-K for the year ended December 31, 2004. During the second quarter of 2005, Pepco identified the following as an additional critical accounting policy.

Unbilled Revenue

Unbilled revenue represents an estimate of revenue earned from services rendered that have not yet been billed. Pepco calculates unbilled revenue using an output based methodology. (This methodology is based on the supply of electricity or gas distributed to customers.) Pepco believes that the estimates involved in its unbilled revenue process represent "Critical Accounting Estimates" because management is required to make assumptions and judgments about input factors such as customer sales mix and estimated power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers), which are all inherently uncertain and susceptible to change from period to period, the impact of which could be material.

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NEW ACCOUNTING STANDARDS

SFAS No. 154

FIN 47

RISK FACTORS

For information concerning risk factors, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in Pepco's Annual Report on Form 10-K for the year ended December 31, 2004.

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 or Pepco's industry's ac tual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements.

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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 with respect to 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 project costs;
·	Unanticipated changes in operating expenses and capital expenditures;
·	The ability to obtain funding in the capital markets on favorable terms;
·	Restrictions imposed by PUHCA;
·	Legal and administrative proceedings (whether civil or criminal) and settlements that influence Pepco'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 market concerns; 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 of such factors, nor can Pepco assess the impact of any such factor on Pepco's business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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

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

DELMARVA POWER & LIGHT COMPANY

GENERAL OVERVIEW

Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and Virginia. DPL also providesnatural gas distribution service in northern Delaware.DPL's electricity distribution service territory covers approximately 6,000 square miles and has a population of approximately1.28 million.As of June 30, 2005, approximately 63% of delivered electricity sales were to Delaware customers, approximately 34% were to Maryland customers, and approximately 3% were to Virginia customers. DPL also provides natural gas distribution service in Northern Delaware. DPL's natural gas distribution service territory covers approximately 275 square miles and has a population of approximately523,000.

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 registered under the Public Utility Holding Company Act of 1935 (PUHCA), the relationship between PHI and DPL and certain activities of DPL are subject to the regulatory oversight of the Securities and Exchange Commission under PUHCA.

RESULTS OF OPERATIONS

The Results of Operations discussion below is presented for the six month period ended June 30, 2005 compared to the six month period ended June 30, 2004. 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.

Electric Operating Revenue

	2005		2004		Change
Regulated T&D Electric Revenue	$	182.5	$	188.6	$	(6.1	)
Default Supply Revenue		308.6		300.8		7.8
Other Electric Revenue		8.9		9.7		(.8	)
Total Electric Operating Revenue	$	500.0	$	499.1	$	.9

The table above shows the amounts of Electric Operating Revenue earned that is subject to price regulation (Regulated T&D (Transmission & Distribution) 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 DPL receives for delivery of electricity to its customers. DPL provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is also known as Default Service in Virginia, Standard Offer Service (SOS) in Maryland, as well as in Delaware on and after May 1, 2006, and Provider of Last Resort service (POLR) in Delaware before May 1, 2006. Default Supply Revenue is revenue received by DPL from Default Electricity Supply. The costs

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related to the supply of electricity are included in Fuel and Purchased Energy. Other Electric Revenue includes work and services performed on behalf of customers including other utilities, which is not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rents, late payments, and collection fees.

Regulated T&D Electric

Regulated T&D Electric Revenue	2005		2004		Change

Residential	$	88.3	$	92.0	$	(3.7	)
Commercial		49.1		52.1		(3.0	)
Industrial		10.0		9.4		.6
Other (Includes PJM)		35.1		35.1		-
Total Regulated T&D Electric Revenue	$	182.5	$	188.6	$	(6.1	)

Regulated T&D Electric Sales (GwH)	2005		2004		Change

Residential		2,706		2,755		(49)
Commercial		2,546		2,564		(18)
Industrial		1,535		1,646		(111)
Other		25		25		-
Total Regulated T&D Electric Sales		6,812		6,990		(178)

Regulated T&D Electric Customers (000s)	2005		2004		Change

Residential		445		438		7
Commercial		59		58		1
Industrial		1		1		-
Other		1		1		-
Total Regulated T&D Electric Customers		506		498		8

Regulated T&D Electric Revenue decreased by $6.1 million to $182.5 million in 2005 from $188.6 million in 2004, due to: (i) $3.4 million due to milder weather, the result of a 27.3% decrease in cooling degree days in 2005, (ii) $1.2 million due to a reduction by DPL in estimated unbilled revenue, primarily reflecting an increase in the amount of estimated power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers), and (iii) $1.5 million of other sales and rate variances. Delivered sales for the six months ended June 30, 2005 were approximately 6,812 GwH compared to approximately 6,990 GwH for the comparable period in 2004.

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Default Electricity Supply

Default Supply Revenue	2005		2004		Change

Residential	$	144.9	$	128.7	$	16.2
Commercial		122.2		124.1		(1.9	)
Industrial		39.9		46.6		(6.7	)
Other (Includes PJM)		1.6		1.4		.2
Total Default Supply Revenue	$	308.6	$	300.8	$	7.8

Default Electricity Supply Sales (GwH)	2005		2004		Change

Residential		2,708		2,735		(27	)
Commercial		2,271		2,332		(61	)
Industrial		820		1,001		(181	)
Other		25		23		2
Total Default Electricity Supply Sales		5,824		6,091		(267	)

Default Electricity Supply Customers (000s)	2005		2004		Change

Residential		444		437		7
Commercial		57		56		1
Industrial		1		1		-
Other		1		1		-
Total Default Electricity Supply Customers		503		495		8

Default Supply Revenue increased by $7.8 million primarily due to the following: (i) $23.1 million due to higher retail energy rates, the result of the implementation of the SOS competitive bid procedure in Maryland beginning in June and July 2004, partially offset by (ii) $8.2 million increased customer migration, (iii) $3.8 million impact of milder weather and (iv) $2.8 million due to a reduction by DPL in estimated unbilled revenue, primarily reflecting an increase in the amount of estimated power line losses.

For the six months ended June 30, 2005, DPL's Delaware customers served by an alternate supplier represented 13% of DPL's total Delaware load and DPL's Maryland customers served by alternate suppliers represented 22% of DPL's total Maryland load. For the six months ended June 30, 2004, DPL's Delaware customers served by an alternate supplier represented 12% of DPL's total Delaware load and DPL's Maryland customers served by alternate suppliers represented 14% of DPL's total Maryland load.

Default Electricity Supply sales for the six months ended June 30, 2005 were approximately 5,824 GwH compared to approximately 6,091 GwH for the comparable period in 2004.

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Natural Gas Operating Revenue

	2005		2004		Change
Regulated Gas Revenue	$	127.9	$	110.9	$	17.0
Other Gas Revenue		31.3		38.3		(7.0	)
Total Natural Gas Operating Revenue	$	159.2	$	149.2	$	10.0

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 for on-system natural gas delivered sales and the transportation of natural gas for customers. Other Gas Revenue includes off-system natural gas sales and the release of excess system capacity.

Regulated Gas

Regulated Gas Revenue	2005		2004		Change

Residential	$	78.4	$	69.3	$	9.1
Commercial		41.4		34.9		6.5
Industrial		5.7		4.5		1.2
Transportation and Other		2.4		2.2		.2
Total Regulated Gas Revenue	$	127.9	$	110.9	$	17.0

Regulated Gas Sales (Bcf)	2005		2004		Change

Residential		5.5		5.7		(.2)
Commercial		3.4		3.4		-
Industrial		0.5		0.6		(.1)
Transportation and Other		3.1		3.4		(.3)
Total Regulated Gas Sales		12.5		13.1		(.6)

Regulated Gas Customers (000s)	2005		2004		Change

Residential		109		108		1
Commercial		9		9		-
Industrial		-		-		-
Transportation and Other		-		-		-
Total Regulated Gas Customers		118		117		1

Regulated Gas Revenue increased by $17.0 million due to a $17.9 million increase, effective November 1, 2004, in the Gas Cost Rate due to higher natural gas commodity costs (offset in Gas Purchased).

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Other Gas Revenue

Operating Expenses

Fuel and Purchased Energy

Fuel and Purchased Energy decreased by $1.4 million to $318.1 million for the six months ended June 30, 2005, from $319.5 million for the comparable period in 2004.

Gas Purchased

Gas Purchased increased by $9.5 million to $120.9 million for the six months ended June 30, 2005 from $111.4 million for the comparable period in 2004. This increase resulted from a (i) $5.7 million increase in wholesale commodity prices and less gas injected into storage, (ii) $9.7 million increase in deferred fuel costs, and (iii) $1.0 million increase from the settlement of financial hedges (entered into as part of DPL's regulated Natural Gas Hedge program), partially offset by (iv) a $6.9 million decrease in costs associated with fewer off-system sales. (Offsets in Regulated Gas Revenue and Other Gas Revenue).

Other Operation and Maintenance

Other Operation and Maintenance increased by $.5 million to $84.8 million for the six months ended June 30, 2005 from $84.3 million for the comparable period in 2004. The increase primarily resulted from: (i) $1.3 million increase in building lease costs, (ii) $.6 million increase associated with additional customer requested work, partially offset by (iii) $1.9 million lower system maintenance and restoration costs.

Other Taxes

Other Taxes increased by $8.0 million to $17.5 million for the six months ended June 30, 2005 from $9.5 million for the comparable period in 2004. The increase primarily resulted from a favorable delivery property tax accrual of $7.1 million.

Income Tax Expense

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RISK FACTORS

For information concerning risk factors, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in DPL's Annual Report on Form 10-K for the year ended December 31, 2004.

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 or DPL's industry's actual res ults, 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 with respect to 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 project costs;

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·	Unanticipated changes in operating expenses and capital expenditures;
·	The ability to obtain funding in the capital markets on favorable terms;
·	Restrictions imposed by PUHCA;
·	Legal and administrative proceedings (whether civil or criminal) and settlements that influence DPL'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 market concerns; 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 reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of anticipated events. New factors emerge from time to time, and it is not possible for DPL to predict all of such factors, nor can DPL assess the impact of any such factor on our 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

ATLANTIC CITY ELECTRIC COMPANY

GENERAL OVERVIEW

Atlantic City Electric Company (ACE) is engaged in the generation, transmission, and distribution of electricity in southern New Jersey. ACE's service territory covers approximately 2,700 square miles and has a population of approximately 998,000.

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 registered under the Public Utility Holding Company Act of 1935 (PUHCA), the relationship between PHI and ACE and certain activities of ACE are subject to the regulatory oversight of the Securities and Exchange Commission under PUHCA.

RESULTS OF OPERATIONS

Operating Revenue

	2005		2004		Change
Regulated T&D Electric Revenue	$	159.2	$	169.2	$	(10.0	)
Default Supply Revenue		433.3		458.7		(25.4	)
Other Electric Revenue		7.5		10.4		(2.9	)
Total Operating Revenue	$	600.0	$	638.3	$	(38.3	)

The table above shows the amounts of Operating Revenue earned that are subject to price regulation (Regulated T&D (Transmission & Distribution) 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 ACE receives for delivery of electricity to its customers. 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 (BGS) in New Jersey. Default Supply Revenue is revenue received by ACE from Default Electricity Supply. The costs related to the supply of electricity are included in Fuel and Purchased Energy. Also included in Default Supply Revenue is revenue from non-utility generators (NUGs), transition bond charges (TBC), mar ket transition charges (MTC) and other restructuring related revenues (see Deferred Electric Service Cost). Other Electric Revenue includes work and services performed on behalf of customers including other utilities, which is not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rents, late payments, and collection fees.

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Regulated T&D Electric

Regulated T&D Electric Revenue	2005		2004		Change

Residential	$	76.7	$	77.9	$	(1.2	)
Commercial		50.7		56.4		(5.7	)
Industrial		8.3		8.4		(.1	)
Other (Includes PJM)		23.5		26.5		(3.0	)
Total Regulated T&D Electric Revenue	$	159.2	$	169.2	$	(10.0	)

Regulated T&D Electric Sales (GwH)	2005		2004		Change

Residential		1,930		2,033		(103	)
Commercial		1,987		2,078		(91	)
Industrial		588		576		12
Other		23		23		-
Total Regulated T&D Electric Sales		4,528		4,710		(182	)

Regulated T&D Electric Customers (000s)	2005		2004		Change

Residential		464		456		8
Commercial		62		61		1
Industrial		1		1		-
Other		1		1		-
Total Regulated T&D Electric Customers		528		519		9

Regulated T&D Electric Revenue decreased by $10.0 million primarily due to the following: (i) $4.0 million due to a reduction by ACE in estimated unbilled revenue, primarily reflecting an increase in the amount of estimated power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers), (ii) $2.1 million due to milder weather, the result of a 15.8% decrease in cooling degree days in 2005 and (iii) $3.9 million due to other sales and rate variances. Delivered sales for the six months ended June 30, 2005 were approximately 4,528 GwH compared to approximately 4,710 GwH for the comparable period in 2004.

Default Electricity Supply

Default Supply Revenue	2005		2004		Change

Residential	$	142.0	$	145.0	$	(3.0	)
Commercial		113.6		126.0		(12.4	)
Industrial		21.3		24.0		(2.7	)
Other (Includes PJM)		156.4		163.7		(7.3	)
Total Default Supply Revenue	$	433.3	$	458.7	$	(25.4	)

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Default Electricity Supply Sales (GwH)	2005		2004		Change

Residential		1,983		2,009		(26	)
Commercial		1,368		1,507		(139	)
Industrial		164		204		(40	)
Other		23		23		-
Total Default Electricity Supply Sales		3,538		3,743		(205	)

Default Electricity Supply Customers (000s)	2005		2004		Change

Residential		464		456		8
Commercial		62		60		2
Industrial		1		1		-
Other		1		1		-
Total Default Electricity Supply Customers		528		518		10

Default Supply Revenue is offset in operating expenses and has minimal earnings impact due to deferral accounting as a result of electric restructuring in New Jersey. The $25.4 million decrease in Default Supply Revenue primarily resulted from: (i) $14.7 million related to increased customer migration, (ii) $7.9 million due to a reduction by ACE in estimated unbilled revenue, primarily reflecting an increase in the amount of estimated power line losses, and (iii) $3.1 million impact of milder weather conditions in the second quarter of 2005.

For the six months ended June 30, 2005, ACE's New Jersey customers served by an alternate supplier represented 27% of ACE's total load. For the six months ended June 30, 2004, ACE's New Jersey customers served by an alternate supplier represented 22% of ACE's total load.

Default Electricity Supply Sales for the six months ended June 30, 2005 were approximately 3,538 GwH compared to approximately 3,743 GwH for the comparable period in 2004.

Other Electric Revenue

Other Electric Revenue decreased by $2.9 million primarily due to the following: (i) $1.5 million lower inter-company lease revenues and (ii) $1.1 million decrease due to a reduction in customer requested work.

Operating Expenses

Fuel and Purchased Energy

Fuel and Purchased Energy decreased by $.1 million to $387.1 million for the six months ended June 30, 2005, from $387.2 million for the comparable period in 2004.

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Other Operation and Maintenance

Other Operation and Maintenance decreased by $5.6 million to $92.4 million for the six months ended June 30, 2005 from $98.0 million for the comparable period in 2004. The decrease primarily resulted from $2.8 million lower restructuring costs.

Depreciation and Amortization

Depreciation and Amortization expenses decreased by $9.6 million to $56.9 million in 2005 from $66.5 million in 2004 primarily due to a decrease in deferred transitional bond charges.

Deferred Electric Service Costs

Gain on Sale of Assets

The Gain on Sale of Assets represents a $14.4 million gain from the condemnation settlement with the City of Vineland, New Jersey relating to the transfer of its distribution assets and customer accounts to the city during the second quarter of 2004.

Other Income (Expenses)

Other Expenses decreased by $2.9 million to a net expense of $23.6 million in 2005 from a net expense of $26.5 million in 2004. This decrease is primarily due to lower interest expense.

Income Tax Expense

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Extraordinary Item

On April 19, 2005, a settlement of ACE's electric distribution rate case was reached among ACE, the staff of the NJBPU, the New Jersey Ratepayer Advocate, and active intervenor parties. As a result of the settlement, ACE reversed $15.2 million ($9.0 million, after-tax) in accruals related to certain deferred costs that are now deemed recoverable.

RISK FACTORS

For information concerning risk factors, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in ACE's Annual Report on Form 10-K for the year ended December 31, 2004.

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 or ACE's industry's actual res ults, 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 with respect to 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;

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·	Growth in demand, sales and capacity to fulfill demand;
·	Changes in tax rates or policies or in rates of inflation;
·	Changes in project costs;
·	Unanticipated changes in operating expenses and capital expenditures;
·	The ability to obtain funding in the capital markets on favorable terms;
·	Restrictions imposed by PUHCA;
·	Legal and administrative proceedings (whether civil or criminal) and settlements that influence ACE'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 market concerns; 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 reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of anticipated events. New factors emerge from time to time, and it is not possible for ACE to predict all of such factors, nor can ACE assess the impact of any such factor on our 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

Pepco Holdings

For information about PHI's derivative activities, please refer to Note (2) Accounting for Derivatives, and Note (13) Use of Derivatives in Energy and Interest Rate Hedging Activities, to the Consolidated Financial Statements of PHI included in its Annual Report on Form 10-K for the year ended December 31, 2004.

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 segments' energy market participation. PHI uses a value-at-risk (VaR) model to assess the market risk of its competitive energy segments' other energy commodity activities and its remaining proprietary trading contracts. PHI also uses other measures to limit and monitor risk in its commodity activities, including limits on the nominal size of positions and periodic loss limits. VaR represents the potential mark-to-market loss on energy contracts or portfolios due to changes in market prices for a specified time period and confidence level. PHI estimates VaR using a delta-gamma variance / covariance model with a 95 percent, one-tailed confidence level and assuming a one-day holding period. Since VaR is an estimate, it is not necessarily indicat ive of actual results that may occur.

Value at Risk Associated with Energy Contracts For the Six Months Ended June 30, 2005 (Dollars in Millions)
	Proprietary Trading VaR (1)	VaR for Competitive Energy Activity (2)
95% confidence level, one-day holding period, one-tailed (3)
Period end	$ 0	$6.7
Average for the period	$ 0	$5.9
High	$ 0	$9.9
Low	$ 0	$2.9

Notes:
(1)	Includes all remaining proprietary trading contracts entered into prior to cessation of this activity in March 2003.
(2)	This column represents all energy derivative contracts, normal purchase & sales contracts, modeled generation output and fuel requirements and modeled customer load obligations for both the discontinued proprietary trading activity and the ongoing other energy commodity activities.
(3)	As VaR calculations are shown in a standard delta or delta/gamma closed form 95% 1-day holding period 1-tail normal distribution form, traditional statistical and financial methods can be employed to reconcile prior 10-K and 10-Q VaRs to the above approach. In this case, 5-day VaRs divided by the square root of 5 equal 1-day VaRs; and 99% 1-tail VaRs divided by 2.326 times 1.645 equal 95% 1-tail VaRs. Note that these methods of conversion are not valid for converting from 5-day or less holding periods to over 1-month holding periods and should not be applied to "non-standard closed form" VaR calculations in any case.

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For additional quantitative and qualitative information on the fair value of energy contracts refer to Note 5, Use of Derivatives in Energy and Interest Rate Hedging Activities in the accompanying Notes to Consolidated Financial Statements.

The competitive energy segments' portfolio of electric generating plants includes "mid-merit" assets and peaking assets. Mid-merit electric generating plants are typically combined cycle units that can quickly change their megawatt output level on an economic basis. These plants are generally operated during times when demand for electricity rises and power prices are higher. The competitive energy segments dynamically (economically) hedge both the estimated plant output and fuel requirements as the estimated levels of output and fuel needs change. Hedge percentages include the estimated electricity output of and fuel requirements for the competitive energy segment's generation plants that have been economically hedged and any associated financial or physical commodity contracts (including derivative contracts that are classified as cash flow hedges under SFAS 133, other derivative instruments, wholesale normal purchase and sales contracts, and load service obligations).

As of June 30, 2005, based on economic availability projections, 75% of generation output is hedged over the next 36 months. Fuel inputs for the same 36-month period are 59% hedged.

Hedge volumes can vary significantly from period to period, as sales may exceed forecast plant output in some periods (a net short position), while in other periods sales may fall short of forecast output (a net long position).

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This table provides information on the competitive energy segments' credit exposure, net of collateral, to wholesale counterparties.

Schedule of Credit Risk Exposure on Competitive Wholesale Energy Contracts (Dollars in Millions)
	June 30, 2005
Rating (1)	Exposure Before Credit Collateral (2)	Credit Collateral (3)	Net Exposure	Number of Counterparties Greater Than10% *	Net Exposure of Counterparties Greater Than 10%

Investment Grade	327.8	-	327.8	2	117.9
Non-Investment Grade	.8	-	.8
Split rating	.1	-	.1
No External Ratings	14.5	-	14.5

Credit reserves			1.4

(1)	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 rating of BBB- or Baa3, respectively. If the counterparty has a split rating (i.e., rating not uniform between major rating agencies), it is presented separately.
(2)	Exposure before credit collateral - includes the 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.
(3)	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).
*	Using a percentage of the total exposure.

For additional information concerning market risk, please refer to Item 7A, Quantitative and Qualitative Disclosure About Market Risk in Pepco Holdings' Annual Report on Form 10-K for the year ended December 31, 2004.

Pepco

For information concerning market risk, please refer to Item 7A, Quantitative and Qualitative Disclosure About Market Risk in Pepco's Annual Report on Form 10-K for the year ended December 31, 2004.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q AND THEREFORE ARE FILING THIS FORM WITH A REDUCED FILING FORMAT.

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Item 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, 2005, 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 SEC under the Securities Exchange Act of 1934 (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, 2005, there was no change in Pepco Holdings' internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pepco Holdings' internal controls over financial reporting.

Potomac Electric Power Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, Pepco has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of June 30, 2005, 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 and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the SEC under the Securities Exchange Act of 1934 (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, 2005, 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, 2005, 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 Securities Exchange Act of 1934 (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, 2005, 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, 2005, 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 Securities Exchange Act of 1934 (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, 2005, 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.

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Part II OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Pepco Holdings

On July 14, 2003, Mirant Corporation and most of its subsidiaries filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code. For additional information, please refer to Note (4), Commitments and Contingencies, to the financial statements of PHI included herein.

For further information concerning litigation matters, please refer to Item 3, "Legal Proceedings," included in Pepco Holdings' Annual Report on Form 10-K for the year ended December 31, 2004 and Note (4), Commitments and Contingencies, to the financial statements of PHI included herein.

Pepco

For further information concerning litigation matters, please refer to Item 3, "Legal Proceedings," included in Pepco's Annual Report on Form 10-K for the year ended December 31, 2004 and Note (4), Commitments and Contingencies, to the financial statements of Pepco included herein.

DPL

For further information concerning litigation matters, please refer to Item 3, "Legal Proceedings," included in DPL's Annual Report on Form 10-K for the year ended December 31, 2004 and Note (4), Commitments and Contingencies, to the financial statements of DPL included herein.

ACE

For further information concerning litigation matters, please refer to Item 3, "Legal Proceedings," included in ACE's Annual Report on Form 10-K for the year ended December 31, 2004 and Note (4), Commitments and Contingencies, to the financial statements of ACE included herein.

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Pepco Holdings

None.

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Pepco

None.

Item 3. DEFAULTS UPON SENIOR SECURITIES

Pepco Holdings

None.

Pepco

None.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Pepco Holdings

(a) The Annual Meeting of Shareholders was held on May 20, 2005.

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

For Term Expiring in 2008:
Edmund B. Cronin, Jr.	Votes cast for: Votes withheld:	155,642,286 2,637,369
Pauline A. Schneider	Votes cast for: Votes withheld:	117,365,953 40,913,702
Dennis R. Wraase	Votes cast for: Votes withheld:	153,819,003 4,460,652

Directors who are continuing in office:

	Term Expires in 2006:	Term Expires in 2007:
	Terence C. Golden	Jack B. Dunn, IV
	George F. MacCormack	Richard B. McGlynn
	Floretta D. McKenzie	Peter F. O'Malley
	Lawrence C. Nussdorf	Frank K. Ross
		William T. Torgerson

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1.	The Board of Directors approved and submitted to a vote of the shareholders an amendment to the Company's Restated Certificate of Incorporation to reinstate the annual election of all members of the Company's Board of Directors.

This proposal passed. The number of shares outstanding on the record date of March 21, 2005 was 188,462,359. Adoption of the proposal required the affirmative vote of the holders of two-thirds of the outstanding shares of Pepco Holdings Common Stock or 125,641,573 shares. There were 151,744,012 votes cast in support of the proposal, 4,624,104 votes cast against the proposal, 1,911,539 votes abstaining and no broker non-votes.

2.	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 2005.

This proposal passed. The number of shares present and entitled to vote on the proposal was 158,279,655. 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 79,139,828 shares. There were 154,985,451 votes cast in support of the proposal, 2,222,240 votes cast against the proposal, 1,071,964 votes abstaining and no broker non-votes.

3.	The Massachusetts State Carpenters Pension Fund presented the following proposal for a shareholder vote at the meeting:
	Resolved: That the shareholders of Pepco Holdings, Inc. ("Company") hereby request that the Board of Directors initiate the appropriate process to amend the Company's governance documents (certificate of incorporation or bylaws) to provide that director nominees shall be elected by the affirmative vote of the majority of votes cast at an annual meeting of shareholders.

The shareholder proposal did not pass. The number of shares present and entitled to vote on the shareholder proposal was 115,943,471. Adoption of the shareholder 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 57,971,736 shares. There were 65,788,940 votes cast against the proposal, 46,384,338 votes cast in support of the proposal, 3,770,193 votes abstaining and 42,336,184 broker non-votes.

Pepco

Effective May 20, 2005, the following persons were elected as the directors of Pepco by the unanimous written consent in lieu of an annual meeting of Pepco Holdings, Inc., the holder of all of the outstanding Pepco common stock, $.01 par value:

Dennis R. Wraase, Chairman
Joseph M. Rigby
Thomas S. Shaw
William J. Sim
William T. Torgerson
Andrew W. Williams

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Item 5. OTHER INFORMATION

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

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) as indicated.

Exhibit No.	Registrant(s)		Description of Exhibit		Reference
10.1		PHI		Severance Agreement of Ronald K. Clark*	Filed herewith.
12.1		PHI		Statements Re: Computation of Ratios	Filed herewith.
12.2		Pepco		Statements Re: Computation of Ratios	Filed herewith.
12.3		DPL		Statements Re: Computation of Ratios	Filed herewith.
12.4		ACE		Statements Re: Computation of Ratios	Filed herewith.
31.1		PHI		Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.2		PHI		Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.3		Pepco		Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.4		Pepco		Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.5		DPL		Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.6		DPL		Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.7		ACE		Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.8		ACE		Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.

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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.
*	Management contract or compensatory plan or arrangement.

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Exhibit 12.1 Statements Re. Computation of Ratios

PEPCO HOLDINGS

		Six Months Ended			For the Year Ended December 31,
		June 30, 2005				2004			2003			2002			2001			2000
		(Dollar Amounts in Millions)

Income before extraordinary item(a)		$	113.5		$	255.5		$	211.1		$	220.2		$	192.3		$	369.1

Income tax expense			74.3			173.2			65.9			124.1			83.5			341.2

Fixed charges:
Interest on long-term debt, amortization of discount, premium and expense			169.6			376.5			381.4			227.2			162.0			221.5
Other interest			9.8			20.6			21.7			21.0			23.8			23.6
Preferred dividend requirements of subsidiaries			1.3			2.8			13.9			20.6			14.2			14.7
Total fixed charges			180.7			399.9			417.0			268.8			200.0			259.8

Non-utility capitalized interest			(.2	)		(.1	)		(10.2	)		(9.9	)		(2.7	)		(3.9	)

Income before extraordinary item, income tax expense, and fixed charges		$	368.3		$	828.5		$	683.8		$	603.2		$	473.1		$	966.2

Total fixed charges, shown above		$	180.7		$	399.9		$	417.0		$	268.8		$	200.0		$	259.8

Increase preferred stock dividend requirements of subsidiaries to a pre-tax amount			.9			1.9			4.3			11.6			6.2			13.5

Fixed charges for ratio computation		$	181.6		$	401.8		$	421.3		$	280.4		$	206.2		$	273.3

Ratio of earnings to fixed charges and preferred dividends			2.03			2.06			1.62			2.15			2.29			3.54

(a)	Excludes losses on equity investments.

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Exhibit 12.2 Statements Re. Computation of Ratios

PEPCO

		Six Months Ended		For the Year Ended December 31,
		June 30, 2005			2004		2003		2002			2001			2000
		(Dollar Amounts in Millions)

Net income(a)		$	35.4	$	96.6	$	104.6	$	141.2		$	192.3		$	369.1

Income tax expense			26.7		56.7		69.1		80.3			83.5			341.2

Fixed charges:
Interest on long-term debt, amortization of discount, premium and expense			39.9		80.7		81.4		112.2			162.0			221.5
Other interest			6.6		14.3		16.2		17.3			23.8			23.6
Preferred dividend requirements of a subsidiary trust			-		-		4.6		9.2			9.2			9.2
Total fixed charges			46.5		95.0		102.2		138.7			195.0			254.3

Non-utility capitalized interest			-		-		-		(.2	)		(2.7	)		(3.9	)

Income before income tax expense, and fixed charges		$	108.6	$	248.3	$	275.9	$	360.0		$	468.1		$	960.7

Ratio of earnings to fixed charges			2.34		2.61		2.70		2.60			2.40			3.78

Total fixed charges, shown above		$	46.5	$	95.0	$	102.2	$	138.7		$	195.0		$	254.3

Preferred dividend requirements, excluding mandatorily redeemable preferred securities subsequent to SFAS No. 150 implementation, adjusted to a pre-tax amount			1.1		1.6		5.5		7.8			7.2			10.6

Total fixed charges and preferred dividends		$	47.6	$	96.6	$	107.7	$	146.5		$	202.2		$	264.9

Ratio of earnings to fixed charges and preferred dividends			2.28		2.57		2.56		2.46			2.32			3.63

(a)	Excludes losses on equity investments.

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Exhibit 12.3 Statements Re. Computation of Ratios

DPL

	Six Months Ended		For the Year Ended December 31,
	June 30, 2005			2004		2003		2002		2001		2000
	(Dollar Amounts in Millions)

Net income	$	36.3	$	66.3	$	53.2	$	49.7	$	200.6	$	141.8

Income tax expense		29.4		49.7		36.4		33.7		139.9		81.5

Fixed charges:
Interest on long-term debt, amortization of discount, premium and expense		18.1		33.0		37.2		44.1		68.5		77.1
Other interest		1.2		2.2		2.7		3.6		3.4		7.5
Preferred dividend requirements of a subsidiary trust		-		-		2.8		5.7		5.7		5.7
Total fixed charges		19.3		35.2		42.7		53.4		77.6		90.3

Income before income tax expense, and fixed charges	$	85.0	$	151.2	$	132.3	$	136.8	$	418.1	$	313.6

Ratio of earnings to fixed charges		4.40		4.30		3.10		2.56		5.39		3.47

Total fixed charges, shown above	$	19.3	$	35.2	$	42.7	$	53.4	$	77.6	$	90.3

Preferred dividend requirements, adjusted to a pre-tax amount		.9		1.7		1.7		2.9		6.3		7.7

Total fixed charges and preferred dividends	$	20.2	$	36.9	$	44.4	$	56.3	$	83.9	$	98.0

Ratio of earnings to fixed charges and preferred dividends		4.21		4.10		2.98		2.43		4.98		3.20

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Exhibit 12.4 Statements Re. Computation of Ratios

ACE

	Six Months Ended		For the Year Ended December 31,
	June 30, 2005			2004		2003		2002		2001		2000
	(Dollar Amounts in Millions)

Income before extraordinary item	$	17.6	$	64.6	$	41.5	$	28.2	$	75.5	$	54.4

Income tax expense		11.4		42.3		27.3		16.3		46.7		36.7

Fixed charges:
Interest on long-term debt, amortization of discount, premium and expense		29.2		62.2		63.7		55.6		62.2		76.2
Other interest		1.8		3.4		2.6		2.4		3.3		4.5
Preferred dividend requirements of subsidiary trusts		-		-		1.8		7.6		7.6		7.6
Total fixed charges		31.0		65.6		68.1		65.6		73.1		88.3

Income before extraordinary item, income tax expense, and fixed charges	$	60.0	$	172.5	$	136.9	$	110.1	$	195.3	$	179.4

Ratio of earnings to fixed charges		1.94		2.63		2.01		1.68		2.67		2.03

Total fixed charges, shown above	$	31.0	$	65.6	$	68.1	$	65.6	$	73.1	$	88.3

Preferred dividend requirements adjusted to a pre-tax amount		.2		.5		.5		1.1		2.7		3.6

Total fixed charges and preferred dividends	$	31.2	$	66.1	$	68.6	$	66.7	$	75.8	$	91.9

Ratio of earnings to fixed charges and preferred dividends		1.92		2.61		2.00		1.65		2.58		1.95

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Exhibit 31.1
CERTIFICATION
I, Dennis R. Wraase, certify that:
1.	I have reviewed this report on Form 10-Q of Pepco Holdings, Inc.
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b)	Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
	c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:
	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: August 8, 2005			D. R. WRAASE Dennis R. Wraase Chairman of the Board, President and Chief Executive Officer

197
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Exhibit 31.2
CERTIFICATION
I, Joseph M. Rigby, certify that:
1.		I have reviewed this report on Form 10-Q of Pepco Holdings, Inc.
2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.		The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b)		Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
	c)		Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d)		Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:
	a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: August 8, 2005				JOSEPH M. RIGBY Joseph M. Rigby Senior Vice President and Chief Financial Officer

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Exhibit 31.3
CERTIFICATION
I, Dennis R. Wraase, certify that:
1.		I have reviewed this report on Form 10-Q of Potomac Electric Power Company.
2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.		The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
	a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b)		Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	c)		Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:
	a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: August 8, 2005				D.R. WRAASE Dennis R. Wraase Chairman of the Board and Chief Executive Officer

199
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Exhibit 31.4
CERTIFICATION
I, Joseph M. Rigby, certify that:
1.	I have reviewed this report on Form 10-Q of Potomac Electric Power Company.
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
		a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		b)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		c)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.		The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: August 8, 2005				JOSEPH M. RIGBY Joseph M. Rigby Senior Vice President and Chief Financial Officer

200
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Exhibit 31.5
CERTIFICATION
I, Thomas S. Shaw, certify that:
1.	I have reviewed this report on Form 10-Q of Delmarva Power & Light Company.
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
		a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		b)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		c)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.		The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: August 8, 2005				T.S. SHAW Thomas S. Shaw President and Chief Executive Officer

201
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Exhibit 31.6
CERTIFICATION
I, Joseph M. Rigby, certify that:
1.	I have reviewed this report on Form 10-Q of Delmarva Power & Light Company.
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
		a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		b)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		c)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.		The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: August 8, 2005				JOSEPH M. RIGBY Joseph M. Rigby Senior Vice President and Chief Financial Officer

202
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Exhibit 31.7
CERTIFICATION
I, William J. Sim, certify that:
1.	I have reviewed this report on Form 10-Q of Atlantic City Electric Company.
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
		a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		b)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		c)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.		The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: August 8, 2005				WILLIAM J. SIM William J. Sim President and Chief Executive Officer

203
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Exhibit 31.8
CERTIFICATION
I, Joseph M. Rigby, certify that:
1.	I have reviewed this report on Form 10-Q of Atlantic City Electric Company.
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
		a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		b)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		c)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.		The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: August 8, 2005				JOSEPH M. RIGBY Joseph M. Rigby Chief Financial Officer

204
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Exhibit 32.1
Certificate of Chief Executive Officer and Chief Financial Officer of Pepco Holdings, Inc. (pursuant to 18 U.S.C. Section 1350)
I, Dennis R. Wraase, and I, Joseph M. Rigby, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Pepco Holdings, Inc. for the quarter ended June 30, 2005, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Pepco Holdings, Inc.
August 8, 2005	D.R. WRAASE Dennis R. Wraase Chairman of the Board, President and Chief Executive Officer
August 8, 2005	JOSEPH M. RIGBY Joseph M. Rigby Senior Vice President and Chief Financial Officer
A signed original of this written statement required by Section 906 has been provided to Pepco Holdings, Inc. and will be retained by Pepco Holdings, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

205
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Exhibit 32.2
Certificate of Chief Executive Officer and Chief Financial Officer of Potomac Electric Power Company (pursuant to 18 U.S.C. Section 1350)
I, Dennis R. Wraase, and I, Joseph M. Rigby, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Potomac Electric Power Company for the quarter ended June 30, 2005, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Potomac Electric Power Company.
August 8, 2005	D.R. WRAASE Dennis R. Wraase Chairman of the Board and Chief Executive Officer
August 8, 2005	JOSEPH M. RIGBY Joseph M. Rigby Senior Vice President and Chief Financial Officer
A signed original of this written statement required by Section 906 has been provided to Potomac Electric Power Company and will be retained by Potomac Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

206
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Exhibit 32.3
Certificate of Chief Executive Officer and Chief Financial Officer of Delmarva Power & Light Company (pursuant to 18 U.S.C. Section 1350)
I, Thomas S. Shaw, and I, Joseph M. Rigby, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Delmarva Power & Light Company for the quarter ended June 30, 2005, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Delmarva Power & Light Company.
August 8, 2005	T.S. SHAW Thomas S. Shaw President and Chief Executive Officer
August 8, 2005	JOSEPH M. RIGBY Joseph M. Rigby Senior Vice President and Chief Financial Officer
A signed original of this written statement required by Section 906 has been provided to Delmarva Power & Light Company and will be retained by Delmarva Power & Light Company and furnished to the Securities and Exchange Commission or its staff upon request.

207
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Exhibit 32.4
Certificate of Chief Executive Officer and Chief Financial Officer of Atlantic City Electric Company (pursuant to 18 U.S.C. Section 1350)
I, William J. Sim, and I, Joseph M. Rigby, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Atlantic City Electric Company for the quarter ended June 30, 2005, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Atlantic City Electric Company.
August 8, 2005	WILLIAM J. SIM William J. Sim President and Chief Executive Officer
August 8, 2005	JOSEPH M. RIGBY Joseph M. Rigby Chief Financial Officer
A signed original of this written statement required by Section 906 has been provided to Atlantic City Electric Company and will be retained by Atlantic City Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.

208
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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.

August 8, 2005

PEPCO HOLDINGS, INC. (PHI)
POTOMAC ELECTRIC POWER COMPANY (Pepco)
DELMARVA POWER & LIGHT COMPANY (DPL)
ATLANTIC CITY ELECTRIC COMPANY (ACE)
(Registrants)

By      JOSEPH M. RIGBY
        Joseph M. Rigby
        Senior Vice President and
        Chief Financial Officer,
            PHI, Pepco and DPL
        Chief Financial Officer, ACE

209
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INDEX TO EXHIBITS FILED HEREWITH
Exhibit No.	Registrant(s)	Description of Exhibit
10.1	PHI	Severance Agreement of Ronald K. Clark
12.1	PHI	Statements Re: Computation of Ratios
12.2	Pepco	Statements Re: Computation of Ratios
12.3	DPL	Statements Re: Computation of Ratios
12.4	ACE	Statements Re: Computation of Ratios
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer

INDEX TO EXHIBITS FURNISHED HEREWITH
Exhibit No.	Registrant(s)	Description of Exhibit
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350

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Pepco 10-Q2005 Q2 Quarterly report

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