Pepco 10-K 2004 FY Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year endedDecember 31, 2004
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 ______________________________________________________________________________

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:
Registrant		Title of Each Class
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in the definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K (applicable to Pepco Holdings and Pepco only).   .
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 ACE meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10-K.

Registrant	Aggregate Market Value of Voting and Non-Voting Common Equity Held by Non-Affiliatesof the Registrant at June 30, 2004	Number of Shares of Common Stock of the RegistrantOutstanding at March 1, 2005
Pepco Holdings	$3.2 billion	188,348,974 ($.01 par value)
Pepco	None (a)	100 ($.01 par value)
DPL	None (b)	1,000 ($2.25 par value)
ACE	None (b)	8,546,017 ($3 par value)

(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-K 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.

DOCUMENTS INCORPORATED BY REFERENCE

     Portions of the Pepco Holdings, Inc. definitive proxy statement for the 2005 Annual Meeting of Shareholders to be filed with the Securities and Exchange Commission on or about March 31, 2005 are incorporated by reference into Part III of this report.

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TABLE OF CONTENTS
			Page
	-	Glossary of Terms	i
PART I
Item 1.	-	Business	1
Item 2.	-	Properties	19
Item 3.	-	Legal Proceedings	20
Item 4.	-	Submission of Matters to a Vote of    Security Holders	25
PART II
Item 5.	-	Market for Registrant's Common Equity, Related    Stockholder Matters and Issuer Purchases of    Equity Securities	26
Item 6.	-	Selected Financial Data	29
Item 7.	-	Management's Discussion and Analysis of    Financial Condition and Results of Operations	32
Item 7A.	-	Quantitative and Qualitative Disclosures    About Market Risk	147
Item 8.	-	Financial Statements and Supplementary Data	152
Item 9.	-	Changes in and Disagreements With Accountants    on Accounting and Financial Disclosure	360
Item 9A.	-	Controls and Procedures	360
Item 9B.	-	Other Information	362
PART III
Item 10.	-	Directors and Executive Officers of the Registrant	364
Item 11.	-	Executive Compensation	368
Item 12.	-	Security Ownership of Certain Beneficial Owners    and Management	375
Item 13.	-	Certain Relationships and Related Transactions	377
Item 14.	-	Principal Accounting Fees and Services	377
PART IV
Item 15.	-	Exhibits, Financial Statement Schedules	378
Financial Statements		Included in Part II, Item 8	378
Schedule I   -		Condensed Financial Information of Parent Company	379
Schedule II  -		Valuation and Qualifying Accounts	382
Exhibit 11   -		Statements Re. Computation of Earnings    Per Common Share	400
Exhibit 12   -		Statements Re. Computation of Ratios	401
Exhibit 21   -		Subsidiaries of the Registrant	405
Exhibit 23   -		Consents of Independent Registered Public   Accounting Firm	407
Exhibits 31.1 - 31.8		Rule 13a-14a/15d-14(a) Certifications	411
Exhibits 32.1 - 32.4		Section 1350 Certifications	419
Signatures			423
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	GLOSSARY OF TERMS
Term	Definition
ABO	Accumulated benefit obligation
Accounting hedges	Derivatives designated as cash flow and fair value hedges
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
Act	Prescription Drug, Improvement and Modernization Act of 2003
ADITC	Accumulated deferred investment tax credits
AFUDC	Allowance for Funds Used During Construction
Agreement and Plan   of Merger	Agreement and Plan of Merger, dated as of February 9, 2001, among PHI, Pepco and Conectiv
Ancillary services	Generally, electricity generation reserves and reliability services
APB	Accounting Principles Board Opinion
APB No. 18	Accounting Principles Board Opinion No. 18, entitled "The Equity Method of Accounting for Investments in Common Stock"
APBO	Accumulated Post-retirement Benefit Obligation
APCA	Air Pollution Control Act
Asset Purchase and   Sale Agreement	Asset Purchase and Sale Agreement, dated as of June 7, 2000 and subsequently amended, between Pepco and Mirant (formerly Southern Energy, Inc.) relating to the sale of Pepco's generation assets
Bankruptcy Court	Bankruptcy Court for the Northern District of Texas
BGS	Basic generation service in New Jersey (the supply of energy to customers who have not chosen a competitive supplier)
BPU Financing Orders	Bondable stranded costs rate orders issued by the NJBPU
BTP	Bondable Transition Property
CAA	Federal Clean Air Act
CBI	Conectiv Bethlehem, LLC
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
CESI	Conectiv Energy Supply, Inc.
Circuit Court	U.S. Court of Appeals for the Fifth Circuit
CO2	Carbon Dioxide
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
Conectiv Power   Delivery	The tradename under which DPL and ACE conduct their power delivery operations
COPCO	Conowingo Power Company
Creditors Committee	The Official Committee of Unsecured Creditors of Mirant Corporation
CRMC	PHI's Corporate Risk Management Committee
CTs	Combustion turbines
CWA	Federal Clean Water Act
DCPSC	District of Columbia Public Service Commission
Debentures	Junior Subordinated Debentures
Delivery revenue	Revenue Pepco receives for delivering energy to its customers
DER	Discrete Emission Reduction Credits
District Court	U.S. District Court for the Northern District of Texas

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Term	Definition
DNREC	Delaware Department of Natural Resources and Environmental Control
DPL	Delmarva Power & Light Company
DPSC	Delaware Public Service Commission
DRP	PHI's Shareholder Dividend Reinvestment Plan
DSR	Default Supply Revenue
EDECA	New Jersey Electric Discount and Energy Competition Act
EDIT	Excess Deferred Income Taxes
EITF	Emerging Issues Task Force
EPA	U.S. 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"
FIN 46	FASB Interpretation No. 46, entitled "Consolidation of Variable Interest Entities"
Financing Order	Financing Order of the SEC under PUHCA dated July 31, 2002 with respect to PHI and its subsidiaries
FirstEnergy	FirstEnergy Corp., formerly Ohio Edison
FirstEnergy PPA	PPAs between Pepco and FirstEnergy Corp. and Allegheny Energy, Inc.
GCR	Gas Cost Recovery
GPC	Generation Procurement Credit
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 generally accepted accounting principles. 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 generally accepted accounting principles, 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.
IRC	Internal Revenue Code
IRS	Internal Revenue Service
ITC	Investment Tax Credit
LEAC Liability	ACE's $59.3 million deferred energy cost liability existing as of July 31, 1999 related to ACE's Levelized Energy Adjustment Clause and ACE's Demand Side Management Programs
LOB	Line of business
LTIP	Pepco Holdings' Long-Term Incentive Plan
MACT	Maximum Achievable Control Technology
Mcf	One thousand cubic feet

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Term	Definition
MDE	Maryland Department of the Environment
MISO	Midwest Independent System Operator
Mirant	Mirant Corporation and certain of its subsidiaries
Mirant Parties	Mirant Corporation and its affiliate Mirant Americas Energy Marketing, LP
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
Moody's	Moody's Investor Service
MPSC	Maryland Public Service Commission
MTC	Market Transition Charge
NERC	North American Electric Reliability Council
NJBPU	New Jersey Board of Public Utilities
NJDEP	New Jersey Department of Environmental Protection
NJPDES	New Jersey Pollutant Discharge Elimination System
Normalization   provisions	Sections of the Internal Revenue Code and related regulations that dictate how excess deferred income taxes resulting from the corporate income tax rate reduction enacted by the Tax Reform Act of 1986 and accumulated deferred investment tax credits should be treated for ratemaking purposes
NOx	Nitrogen oxide
NPDES	National Pollutant Discharge Elimination System
NSR	New Source Review
NUG	Non-Utility Generation
OCI	Other Comprehensive Income
O&M	Operating and maintenance expenses
Panda	Panda-Brandywine, L.P.
Panda PPA	PPA between Pepco and Panda
PARS	Performance Accelerated Restricted Stock
PBO	Projected benefit obligations
PCI	Potomac Capital Investment Corporation and its subsidiaries
PEI	Pepco Enterprises, Inc.
Pepco	Potomac Electric Power Company
Pepco's pre-merger subsidiaries	PCI and Pepco Energy Services
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 each of the Mirant Parties
Pepcom	Pepco Communications, Inc.
PJM	PJM Interconnection, LLC
POLR	Provider of Last Resort (the supply of energy to customers who have not chosen a competitive supplier)
POM	Pepco Holdings' NYSE trading symbol
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
PSD	Prevention of Significant Deterioration
PUHCA	Public Utility Holding Company Act of 1935
RARC	Regulatory Asset Recovery Charge
RCN	RCN Corporation
Recoverable stranded   costs	The portion of stranded costs that is recoverable from ratepayers as approved by regulatory authorities

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Term	Definition
Regulated electric   revenues	Revenues for delivery (transmission and distribution) service and electricity supply service
Retirement Plan	PHI's noncontributory retirement plan
RI/FS	Remedial Investigation/Feasibility Study
S&P	Standard & Poors
SEC	Securities and Exchange Commission
Settlement Agreement	Amended Settlement Agreement and Release, dated as of October 24, 2003 between Pepco and the Mirant Parties
SFAS	Statement of Financial Accounting Standards
SFAS No. 5	Financial Accounting Standards Board Statement No. 5, entitled "Accounting for Contingencies"
SFAS No. 13	Statement of Financial Accounting Standards No. 13, entitled "Accounting for Leases"
SFAS No. 34	Statement of Financial Accounting Standards No. 34, entitled "Capitalization of Interest Cost"
SFAS No. 71	Statement of Financial Accounting Standards No. 71, entitled "Accounting for the Effects of Certain Types of Regulation"
SFAS No. 87	Statement of Financial Accounting Standards No. 87, entitled "Employers' Accounting for Pensions"
SFAS No. 106	Statement of Financial Accounting Standards No. 106, entitled "Employers' Accounting for Post-retirement Benefits Other Than Pensions"
SFAS No. 115	Statement of Financial Accounting Standards No. 115, entitled "Accounting for Certain Investments in Debt and Equity Securities"
SFAS No. 123	Statement of Financial Accounting Standards No. 123, entitled "Accounting for Stock-Based Compensation"
SFAS No. 131	Statement of Financial Accounting Standards No. 131, entitled "Disclosures About Segments of an Enterprise and Related Information"
SFAS No. 132	Statement of Financial Accounting Standards No. 132, entitled "Employers' Disclosures About Pensions and Other Post-retirement Benefits"
SFAS No. 133	Statement of Financial Accounting Standards No. 133, entitled "Accounting for Derivative Instruments and Hedging Activities"
SFAS No. 141	Statement of Financial Accounting Standards No. 141, entitled "Business Combinations"
SFAS No. 142	Statement of Financial Accounting Standards No. 142, entitled "Goodwill and Other Intangible Assets"
SFAS No. 143	Statement of Financial Accounting Standards No. 143, entitled "Accounting for Asset Retirement Obligations"
SFAS No. 144	Statement of Financial Accounting Standards No. 144, entitled "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS No. 150	Statement of Financial Accounting Standards No. 150, entitled "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity"
SMECO	Southern Maryland Electric Cooperative, Inc.
SMECO Agreement	Capacity purchase agreement between Pepco and SMECO
SO2	Sulfur dioxide
SOS	Standard Offer Service (the supply of energy to customers who have not chosen a competitive supplier)
SPEs	Special Purpose Entities as defined in FIN 46R
Standard Offer Service revenue or SOS revenue	Revenue each of Pepco and DPL, respectively, receives for the procurement of energy by it for its SOS customers
Starpower	Starpower Communications, LLC

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Term	Definition
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
TOPrS	Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Which Holds Solely Parent Junior Subordinated Debentures
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
VEBA	Voluntary Employee Beneficiary Association
VRDB	Variable Rate Demand Bonds
VSCC	Virginia State Corporation Commission

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Item 1.    BUSINESS

OVERVIEW

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

· regulatedelectricity and natural gas delivery,

· competitive energy generation, marketing and supply, and

· other activities consisting primarily of investments in energy-related assets.

     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 ofcapital 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 withthe combination of DPL and ACE. As a result, DPL and ACE are wholly owned subsidiaries of Conectiv, which also is a registered public utility holding company under PUHCA. The following chart shows, in simplified form, the corporate structure of PHI and its principal subsidiaries.

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     PHI Service Company, a subsidiary service company of PHI, provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services toPHI and its operating subsidiaries. These services are provided pursuant to a service agreement among PHI, PHI Service Company, and the participating operating subsidiaries which 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 withcost allocationmethodologies set forth in the service agreement.

     For financial information relating to PHI's segments, see Note (3) Segment Information to the consolidated financial statements of PHI set forth in Item 8 of this Form 10-K. This segment information includes a revision of PHI's segments for 2003 and 2002 to reflect that, as of January 1, 2004, the formerly separate segments of Pepco Power Delivery and Conectiv Power Delivery were combined to form one operating segment. Each of Pepco, DPL and ACE has one operating segment.

Investor Information

     Each of PHI, Pepco, DPL and ACE is a reporting company under theSecuritiesExchange Act of 1934, as amended (the Exchange Act). Their Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports, are made available free of charge on PHI's internet Web site as soon as reasonably practicable after such documents are electronically filed with or furnished to the SEC. These reports may be found at http://www.pepcoholdings.com/investors/index_secfilings.html.

     The following is a description of each of PHI's areas of operation.

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. In 2004, 2003 and 2002, respectively,PHI's power delivery operations produced61%,55%, and 58% of PHI's consolidated operating revenues and70%,82%and 78%of PHI's consolidated operating income.

     PHI's power delivery business is conducted by its subsidiaries Pepco, DPL and ACE, each of which is a regulated public utility in the jurisdictions in which it serves customers. DPL and ACE conduct their power delivery operations under the tradename Conectiv Power Delivery. In the aggregate, PHI's power delivery business delivers electricity to more than1.8 million customers in the mid-Atlantic region and distributes natural gas to approximately118,000 customers in Delaware.

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

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     Transmission of Electricity and Relationship with PJM

     The transmission facilities owned by Pepco, DPL and ACE are interconnected with the transmission facilities of contiguous utilities and as such are part of an interstate power transmission grid over which electricity is transmitted throughout the mid-Atlantic region and the eastern United States. The Federal Energy Regulatory Commission (FERC) has designated a number of regional transmission operators to coordinate the operation of portions of the interstate transmission grid. Pepco, DPL and ACE are all members of PJM Interconnection, LLC (PJM), the regional transmission operator that coordinates the movement of electricity in all or parts of Delaware, Maryland, New Jersey, Ohio, Pennsylvania, Virginia, West Virginia and the District of Columbia. FERC has designated PJM as the sole provider of transmission service in the PJM territory. Any entity that wishes to deliver electricity at any point in PJM's territory must obtain transmission ser vices from PJM at rates approved by FERC. In accordance with FERC rules, Pepco, DPL, ACE and the other utilities in the region make their transmission facilities available to PJM and PJM directs and controls the operation of these transmission facilities. In return for the use of their transmission facilities, PJM pays the member utilities transmission fees approved by FERC.

     In recent months, the PJM wholesale electricity marketplace has expanded substantially with the addition of companies delivering power in large portions of the Midwest, and their associated generation; additional expansion of PJM into Virginia and North Carolina is planned. This expansion is forecast to lower PJM transaction costs through greater administrative efficiencies of scale, and the addition of low-cost Midwest generation to the marketplace is expected to result in a lower average hourly energy price in the PJM market for next-day deliveries. In connection with this expansion, FERC has ordered the elimination of "through-and-out" transmission rates for energy transactions within the combined regional markets of PJM and the Midwest Independent System Operator (MISO), effective December 1, 2004, and has established transitional surcharges in PJM and MISO for the ensuing 16-month period, which are intended to recoup a portion of the "th rough-and-out" transmission revenue no longer collected by certain transmission owners in the combined region. The data underlying this transition charge and various exclusions from the charge are disputed by a majority of the utilities, including Pepco, DPL and ACE, and many other parties, including subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv Energy) and Pepco Energy Services, Inc. (together with its subsidiaries, Pepco Energy Services); any amounts collected prior to FERC's decision are subject to refund. FERC's eventual decision cannot be predicted.

     Distribution of Electricity and Deregulation

     Historically, electric utilities, including Pepco, DPL and ACE, were vertically integrated businesses that generated all or a substantial portion of the electric power that they delivered to customers in their service territories over their own distribution facilities. Customers were charged a bundled rate approved by the applicable regulatory authority that covered both the supply and delivery components of the retail electric service. However,recent legislative and regulatory actionsin each of the service territories in which Pepco, DPL and ACE operate have resulted in the "unbundling" of the supply and delivery components of retail electric service and in the opening of the supply component to competition from non-regulated providers. Accordingly, while Pepco, DPL and ACE continue to b e responsible for the distribution of electricity in their respective service territories, as the result of deregulation, customers in those service territories now are

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permitted to choose their electricity supplier from among a number of non-regulated, competitive suppliers. Customers who do not choose a competitive supplier receive default electricity supply from suppliers on terms that vary depending on the service territory, as described more fully below.

     In connection with the deregulation of electric power supply, Pepco, DPL and ACE have divested substantially all of their generation assets, either by selling them to third parties or transferring them to the non-regulated affiliates of PHI that comprise PHI's competitive energy businesses. Accordingly, Pepco, DPL and ACE are no longer engaged in generation operations, except for the limited generation activities of ACE described below.

     Seasonality

     The power delivery business is seasonal and weather patterns can have a material impact on operating performance. In the region served by PHI, demand for electricity is generally greater in the summer months associated with cooling and demand for electricity andnaturalgas is generally greater in the winter months associated with heating, as compared to other times of the year. Historically, the power delivery operations of each of PHI's utility subsidiaries have generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.

     Regulation

     The retail operations of PHI's utility subsidiaries, including the rates they are permitted to charge customers for the delivery of electricity and natural gas, are subject to regulation by governmental agencies in the jurisdictions in which they provide utility service. Pepco'selectricity deliveryoperations are regulated in Maryland by the Maryland Public Service Commission (MPSC) and in Washington, D.C. by the District of Columbia Public Service Commission (DCPSC). DPL'selectricity deliveryoperations are regulated in Maryland by the MPSC, in Virginia by the Virginia State Corporation Commission (VSCC) and in Delaware by the Delaware Public Service Commission (DPSC). DPL'snaturalgas distribution operations in Delaware are regulated by the DPSC. ACE'selectricity deliveryoperations are regulated in New Jersey by the New Jersey Board of Public Utilities (NJBPU). The wholesale and transmission operations for both electricity and natural gas of each of PHI's utility subsidiaries are regulated by FERC.

     Pepco

     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. Pepco was incorporated in Washington, D.C. in 1896 and became a domestic Virginia corporation in 1949. Pepco's service territory covers approximately 640 square miles and has a population of approximately2 million. As of December 31,2004, Pepco delivered electricity to approximately737,000 customers, as compared to726,000 customers as of December 31,2003. Pepco delivered a total ofapproximately 26,902,000 megawatt hours of electricity in2004, compared to approximately 25,994,000 megawatt hours in2003. In 2004, approximately30% was delivered to residential customers,51% to commercial customers, and19% to United States and District of Columbia government customers.

     Under settlements approved by the MPSC and the DCPSC in connection with the divestiture of its generation assets in 2000, Pepcowas required to provide default electricity supply to customers in Maryland through June2004

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and to customers in Washington, D.C. through February7, 2005, for which itwas paid established rates set forth in the settlements. Pepco obtained all of the energy and capacity needed to fulfillthese fixed-ratedefault supply obligations in Maryland and Washington, D.C. through January 22, 2005, from an affiliate of Mirant Corporation (Mirant). See Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Relationship with Mirant Corporation."

     Under a settlement approved by the MPSC in April 2003 addressing default supply, also known as Standard Offer Service (SOS), in Maryland following the expiration of Pepco's fixed-rate default supply obligations in July 2004, Pepco is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customersthrough May 2006,andto large commercial customers through May 2005. Pepco also has an obligation to provide service at hourly priced market rates to the largest customers through May 2006. In accordance with the settlement, Pepcopurchases the power supply required to satisfy its marke t ratedefault supply obligation fromwholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved by the MPSC. Pepcois entitledto recover from itsdefault supply customers thecost of thedefault supplyplus an average margin of approximately $0.002 per kilowatt hour, calculated based on total sales to residential, small, and large commercial Maryland default customers over the twelve months ended December 31, 2003. Because margins vary by customer class, the actual average margin over any given time period depends on the number of Maryland default supply customers from each customer class and the load taken by such customers ove r the time period. Pepco is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both default supply customers and customers in Maryland who have selected another energy supplier. These delivery rates generally were capped originally through June 2004 as a result of a settlement agreement and the Electric Choice and Competition Act of 1999, and extended through December 31, 2006 pursuant to the MPSC order issued in April 2002 in connection with the merger involving Pepco and Conectiv.

     Under an order issued by the DCPSC in March 2004 addressing default supply in the District of Columbia after the expiration of Pepco's fixed-rate default supply obligations in February 2005, as amended by a DCPSC order issued in July 2004, Pepco's obligation to provide default electricity supply at market rates was extended for up to an additional 76 months for small commercial and residential customers and an additional 28 months for large commercial customers. Pepco purchases the power supply required to satisfy its market rate default supply obligation from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved by the DCPSC. Subsequent orders issued by the DCPSC provide for Pepco to recover from its default supply customers thecosts associated with the acquisition of the default supply plus administrative charges that are intended to allow Pepco to recover the administrative costs incurred to provide the default electricity supply. These administrative charges include an average margin for Pepco of approximately $0.00248 per kilowatt hour, calculated based on total sales to residential, small and large commercial District of Columbia default customers over the twelve months ended December 31, 2003. Because margins vary by customer class, the actual average margin over any given time period depends on the number of District of Columbia default supply customers from each customer class and the load taken by such customers over the time period. Pepco is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both default supply customers and customers in the District of Columbia who have selected another energy supplier. Assuming no change as a

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result of the current Pepco distribution rate review case in the District of Columbia (see Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Rate Proceedings"), delivery rates in the District of Columbia generally are capped through July 2007, except with respect to residential low-income customers, for whom rates generally are capped through July 2009.

     For the twelve months ended December 31,2004, Pepco delivered 71% of its load (measured by megawatt hours) to Marylanddefault supply customers, as compared to70% in2003. Pepco delivered 68% of its load to District of Columbiadefault supply customers in 2004, as compared to 52% in 2003.

     DPL

     DPL is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and Virginia and providesnaturalgas distribution service in northern Delaware. In Delaware, service is provided in three counties, Kent, New Castle, and Sussex; in Maryland, service is provided in ten counties, Caroline, Cecil, Dorchester, Harford, Kent, Queen Anne's, Somerset, Talbot, Wicomico, and Worchester; and in Virginia, service is provided to two counties, Accomack and Northampton. DPL was incorporated in Delaware in 1909 and became a domestic Virginia corporationin 1979. DPL's electricity distribution service territory covers approximately 6,000 square miles and has a population of approximately1.28 million. DPL's natural gas distribution servic e territory covers approximately 275 square miles and has a population of approximately523,000. As of December 31,2004, DPL delivered electricity to approximately501,000customers and delivered natural gas to approximately118,000 customers, as compared to 493,000electricity customers and117,000 natural gas customers as of December 31,2003.

     In2004, DPL delivered a total ofapproximately 13,902,000 megawatt hours of electricity to itscustomers, as compared toa total of approximately 14,032,000 megawatt hours in 2003. In 2004, approximately 39% of DPL's retail electricity deliveries were to residential customers,38% were to commercial customers and23% were to industrial customers. In 2004, DPL delivered approximately 21,600,000 Mcf (one thousand cubic feet) ofnaturalgas to retail customers in its Delaware service territory, as compared to approximately 22,900,000 Mcf in 2003. In 2004, approxim ately 40% of DPL's retail gas deliveries were sales to residential customers, 26% were to sales commercial customers, 5% were to sales industrial customers, and 29% were sales to customers receiving a transportation-only service.

     Under a settlement approved by the DPSC, DPL is required to provide default electricity supply, or SOS, to customers in Delaware through April 2006.DPL is paid for default supply to customers in Delaware at fixed rates established in thesettlement. DPL obtains all of the energyneeded to fulfill itsdefault supply obligationsin Delawareunder a supply agreement withits affiliate Conectiv Energy, which terminates in May 2006. DPL does not make any profit or incur any loss on the supply component of thedefault power that it delivers to its Delaware customers. DPL is paid tariff delivery ratesfor the delivery of electricity over its transmission and distribution facilities to both default supply customers and customers who have selected another energy supplier. These delivery rates generally are frozen through April 2006, except that DPL is allowed to file for a one-time transmission rate change during this period. On February 22, 2005, the DPSC voted to approve an SOS process that will allow a Wholesale Standard Offer Service Model with DPL as the SOS Supplier. Issues including the length of this extension and any margin that DPL may be able to earn and retain in

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conjunction with this service have been deferred for further discussion and will be decided by the DPSC at a later date. A written DPSC order documenting this decision is expected sometime in March or April 2005.

     Under a settlement approved by the MPSC, DPLwas required to provide default electricity supply to non-residential customers in Marylandthrough May 2004 and to residential customers in Marylandthrough June 2004 for which it was paid established rates set forth in the settlement. DPL obtained all of the energy needed to fulfill its fixed-rate default supply obligations in Maryland under a supply agreement with Conectiv Energy.

     Under a settlement approved by the MPSC in April 2003 addressing default supply in Maryland following the expiration of DPL's fixed-rate default supply obligations in 2004, DPL is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customersthrough May 2006, and to large commercial customers through May 2005. In accordance with the settlement, DPLpurchases the power supply required to satisfy its market ratedefault supply obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved and supervised by the MPSC. DPL is entitled to recover from itsdefault supply customers the costsof thedefault supplyplus an average margin of $0.002 per kilowatt hour, calculated based on total sales to residential, small, and large commercial Maryland default customers over the twelve months ended December 31, 2003. Because margins vary by customer class, the actual average margin over any given time period depends on the number of Maryland default supply customers from each customer class and the load taken by such customers over the time period. DPL is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both default supply customers and customers in Maryland who have selected another energy supplier. These delivery ra tes generally are capped through December 2006.

     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 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. A prior agreement, also with Conectiv Energy, terminated effective December 31, 2004. The current contract was entered into after conducting a competitive bid procedure and Conectiv Energy was the lowest bidder to provide wholesale power supply for DPL's Virginia default service customers. The new supply agreement commenced January 1, 2005 and expires in May 2006. On October 26, 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 dated November 17, 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 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 17 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 Office of Attorney General. The VSCC ruled on January 18, 2005, that the administrative charge and margin are base rate items not recoverable through a fuel clause. No appeal is planned regarding this

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filing. A settlement resolving all other issues and making the interim rates final was filed on March 4, 2005, contingent only on possible future adjustment depending on the result of a related proceeding at FERC. A hearing is scheduled for March 16, 2005, and the VSCC is expected to approve the settlement.

     DPL is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both Virginia default service customers and customers in Virginia who have selected another energy supplier. These delivery rates generally are frozen until December 31, 2010, except that DPL can propose two changes in delivery rates - one prior to July 1, 2007 and another between July 1, 2007 and December 31, 2010.

     In Maryland, DPL sales to default supply customers represented 80% of total delivered megawatt hours for the twelve months ended December 31,2004,as compared to96% in2003.In Delaware, DPL sales to default supply customers represented 89% of total delivered megawatt hours for the twelve months ended December 31, 2004, as compared to87% in2003, and DPL sales to Virginia default supply customers represented 100% of total delivered megawatt hoursin both2004 and2003.

     DPL also provides regulated natural gas supply and distributionserviceto customers in its Delaware natural gas service territory. Large and medium volume commercial and industrialnaturalgas customers may purchasenaturalgas either from DPL or from other suppliers. DPL uses its natural gas distribution facilities to transportgas for customers that choose to purchase natural gas from other suppliers. These customers pay DPL distribution service rates approved by the DPSC. DPL purchases natural gas supplies forresale to its sales service customers from marketers and producers through a combination oflong-term agreements andnext day delivery arrangements. For the twelve months ended December 31,2004, DPL supplied 71.8% of the natural gas that it delivered, compared to 71.6% in 2003.

     ACE

     ACE is engaged in the generation, transmission and distribution of electricity in Gloucester, Camden, Burlington, Ocean, Atlantic, Cape May, Cumberland and Salem counties in southern New Jersey. ACE was incorporated in New Jersey in 1924. ACE's service territory covers approximately 2,700 square miles and has a population of approximately998,000. As of December 31,2004, ACE delivered electricity to approximately524,000 customers in its service territory, as compared toapproximately 521,000 customers as of December 31,2003. ACE delivered a total ofapproximately 9,874,000 megawatt hours of electricity in2004 compared t o approximately 9,643,000 megawatt hours in 2003. In 2004,approximately44% was delivered to residential customers,44% was delivered to commercial customers and12% was delivered to industrial customers.

     Customers in New Jersey who do not chooseanother supplier receive default electricity supply from suppliers selected through auctions approved by the NJBPU. ACE has entered into supply agreements with thedefault suppliers, including Conectiv Energy, on behalf of the default supply customers in its service territory. Each of these agreements requires thedefault supplier to provide a portion of thedefault supply customer load with full requirements service, consisting of power supply and transmission service. ACE delivers thedefault supply tocustomers. ACE is paid tariff rates established by the NJBPU that compensate it f or thecost of obtaining

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the default supply. ACE does not make any profit or incur any loss on the supply component ofthe default power it provides to customers.

     ACE is paid tariff delivery rates for thedelivery of electricity over its transmission and distribution facilities toboth default supply customers andcustomers in its service territory who have selectedanother energy supplier. ACE currently is involved in a base rate proceeding in which it has requested an increase in its delivery rates. See Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Rate Proceedings."

     ACE sales to New Jersey default supply customers represented 76% of total delivered megawatt hours for the twelve months ended December 31,2004,as compared to91% in2003.

     As of December 31,2004, ACE ownedone electric generatingfacility, the B.L. England generating facility, and interests in two facilities jointly owned with other companies. The combined generating capacity of these facilities is555 megawatts. See Item 2 -- "Properties."ACE also has contracts with non-utility generators under which ACE purchased3.9 million megawatt hours of power in2004. ACE sells the electricity produced by the generating facilities and purchased under the non-utility generator contracts in the wholesale market administered by PJM. During2004, ACE's generation and wholesale ele ctricity sales operations produced approximately 23.2% of ACE's operating revenue.

     On March 1, 2004, ACE transferred ownership of the 185 megawatt capacity Deepwater generating facility to Conectiv Energy.

     In April 2004, PHI, Conectiv and ACE entered into a preliminary settlement agreement with the New Jersey Department of Environmental Protection (NJDEP) and the Attorney General of New Jersey that provides that, contingent upon the receipt of necessary approvals from applicable regulatory authorities and the receipt of permits to construct certain electric transmission facilities in southern New Jersey, ACE will permanently cease operation of the B.L. England generating facility by December 15, 2007. See Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Preliminary Settlement Agreement with the NJDEP."

     In 2002, ACE and the City of Vineland, New Jersey entered into a condemnation settlement agreement which provided for ACE to sell the electric distribution facilities within the city limits, and the approximately 5,400 related customer accounts (to which ACE delivered approximately 103,000 megawatt hours of power in 2003), for $23.9 million. The proceedswere received in installmentsand the sale was completed in the second quarter of 2004.

     ACE Funding

     ACE Funding was incorporated in New Jersey in 2001 by ACE. Under New Jersey law, ACE (or a financing entity) is permitted to securitize authorized portions of ACE's recoverable stranded costs through the issuance of bonds (Transition Bonds) and to collect from its customers charges sufficient to fund principal and interest payments on the Transition Bonds and related taxes, expenses and fees. The right to collect the Transition Bond charges is known as Bondable Transition Property. The sole purpose for the establishment of ACE Funding is to issue Transition Bonds, the proceeds of

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which are transferred to ACE in exchange for the related Bondable Transition Property.

Competitive Energy

     PHI's competitive energy business provides non-regulated generation, marketing and supply of electricity andnaturalgas, and related energy management services, in the mid-Atlantic region. In2004, 2003 and 2002, respectively, PHI's competitive energy operations produced 50%, 55%and 48%of PHI's consolidated operating revenues. In 2004 and 2002, respectively, PHI's competitive energy operations produced 19% and 12% of PHI's consolidated operating income. In2003, PHI's competitive energy operations incurred an operating loss equal to 19% of PHI's consolidated operating income. PHI's competitive energy operations are conducted through subsidiarie s of Conectiv Energy and Pepco Energy Services.

     Conectiv Energy

     Conectiv Energy provides wholesale electric power, capacity, and ancillary services in the wholesale markets administered by PJM and also supplies electricity to other wholesale market participants under long-term bilateral contracts. Among its bilateral contractsare the power supplyagreements under which Conectiv Energy sells to DPL itsdefault electricity supply for distribution to customers in Delaware and Virginia. Conectiv Energy also sellsdefault supply to customers in ACE's service territory and to otherdefault supply customers in New Jersey. Other than itsdefault supply sales, Conectiv Energy does not currently participate in the retail competitive power sup ply market. Conectiv Energy obtains the electricity required to meet its power supply obligations from its owngenerating plants, from bilateral contract purchases from other wholesale market participants and from purchases in the wholesale market administered by PJM.

     Conectiv Energy's generation asset strategy focuses on mid-merit plants with operating flexibility and multi-fuel capability that can quickly change their output level on an economic basis. Like "peak-load" plants, mid-merit plants generally operate during times when demand for electricity rises and prices are higher. However, mid-merit plants usually operate for longer periods of time and for more weeks a year than peak-load plants. Conectiv Energy's most recently added mid-merit plant, a combined cycle plant located in Bethlehem, Pennsylvania with a generating capacity of 1,092 megawatts,became fully operational in June 2004. On March 1, 2004, Conectiv Energy received ownership of the 185 megawatt capacity Deepwater generating facility from ACE. As of December 31, 2004, Conectiv Energy owned and operated mid-merit plants with a combined2,689 megawatts of capacity, peak-load plants with a combined669 megawatts of capacity and base-load generating plants with a combined 340 megawatts of capacity. See Item 2 -- "Properties." Conectiv Energy also owns three uninstalled combustion turbines with a book value of $57.0 million. Conectiv Energy will determine whether to install these turbines as part of an existing or new generating facility or sell the turbines to a third party based upon market demand and transmission system needs and requirements.

     Conectiv Energy also sells natural gas and fuel oil to very large end-users and to wholesale market participants under bilateral agreements. Conectiv Energy obtains the natural gas and fuel oil required to meet its supply obligations through market purchases for next day delivery and under long-term bilateral contracts with other market participants.

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     Conectiv Energy actively engages in commodity risk management activities to reduce its financial exposure to changes in the value of its assets andobligations due to commodity price fluctuations. Certain of these risk management activities are conducted using instruments classified as derivatives, such as forward contracts, futures, swaps, and exchange-traded and over-the-counter options. Conectiv Energy also manages commodity risk with contracts that are not classified as derivatives. Conectiv Energy has two primary risk management objectives:  to manage the spread between the cost of fuel used to operate its electric generation plants and the revenue received from the sale of the power produced by those plants; and to manage the spread between its POLR, SOS, and BGS load supply contracts in or der to ensure stable and known minimum cash flows and fix favorable prices and margins when they become available. To a lesser extent, Conectiv Energy also engages in market activities in an effort to profit from short-term geographical price differentials in electricity prices among markets.

     Conectiv Energy's goal is to hedge economically 75% of both the expected power output of its generation facilities and the expected costs of fuel used to operate those facilities. The economic hedge goals are approved by PHI's Corporate Risk Management Committee and may change from time to time based on market conditions. However, the actual level of hedging coverage may vary from this goal. InJuly 2003, Conectiv Energy entered into an agreementwith an international investment banking firm consisting of a series of energy contracts designed to more effectively hedge approximately 50% of Conectiv Energy's generation output and approximately 50% of its supply obligations, with t he intention of providing Conectiv Energy with a more predicable earnings stream during the term of the agreement, which expires in May 2006. The agreement consists of two major components: (i) a fixed price energy supply hedge that is used to reduce Conectiv Energy's financial exposure under its currentdefault supply commitment to DPLin Delaware through May 2006 and Virginia through December 2004and (ii) a generation off-take agreement under which Conectiv Energy receives a fixed monthly payment from the counterparty, and the counterparty receives the profit realized from the sale of approximately 50% of the electricity generated by Conectiv Energy's plants (excluding the Edge Moor facility).

     Pepco Energy Services

     Pepco Energy Services sells retail electricity and natural gas to residential, commercial, industrial and governmental customers in the mid-Atlantic region. Pepco Energy Services also provides integrated energy managementservices to commercial, industrial and governmental customers, including energy-efficiency contracting, development and construction of "green power" facilities, central plant and other equipment operation and maintenance, fuel management, and home service agreements for residential customers. Subsidiaries of Pepco Energy Services provide 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 in the Washington, D.C. area.

     Pepco Energy Services owns peak-load electricity generation plants with approximately 800 megawatts of peak-load capacity, the output of which is sold in the wholesale market administered by PJM. See Item 2 -- "Properties."

     Pepco Energy Services actively engages in commodity risk management activities to reducethe financial exposureto changes in the value of its supply contracts and sales commitments due to commodity priceand volume fluctuations. Certain of these risk management activities are conducted

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using instruments classified as derivatives, such as forward contracts, futures, swaps, and exchange-traded and over-the-counter options. Pepco Energy Services' primary risk management objective is to manage the spread between its retail electric and natural gas sales commitments and the cost of supply used to service those commitmentsin order to secure favorable margins. Because of the age and design of Pepco Energy Services' power plants, these facilities have a high variable cost of operation and Pepco Energy Servicesgenerally does not hedge the output of these plants.

     Competition

     The unregulated energy generation, supply and marketing businesses in the mid-Atlantic region are characterized by intense competition at both the wholesale and retail levels. At the wholesale level, Conectiv Energy and Pepco Energy Services compete with numerous non-utility generators, independent power producers, wholesale power marketers and brokers, and traditional utilities that continue to operate generation assets. In the retailenergy supply market and in providing energy management services, Pepco Energy Services competes with numerous competitive energy marketers and other service providers. Competition in both the wholesale and retail markets for energy and energy management services is based primarily on price and, to a lesser extent, the range of s ervices offered to customers and quality of service.

     Seasonality

     Like the power delivery business, the power generation, supply and marketing businesses are seasonal and weather patterns can have a material impact on operating performance. Demand for electricity generally is greater in the summer months associated with cooling and demand for electricity andnaturalgas generally is greater in the winter months associated with heating, as compared to other times of the year. Historically, the competitive energy operations of Conectiv Energy and Pepco Energy Services have generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Energy management services generally are not seasonal.

Other Non-Regulated

     This component of PHI's business is conducted through its subsidiary Potomac Capital Investment Corporation (PCI). PHI's subsidiary Pepco Communications, Inc. (Pepcom) ceased operations in December 2004 following the sale of its principal asset described below.

     PCI

     PCI manages a portfolio of financial investments, whichconsistsprimarilyof energy leveraged leases. These transactions involve PCI's purchase and leaseback of utility assets located outside of the United States.In 2003 PCI discontinued making new investments, and in 2004 sold its three remaining aircraft. For additional information relating to PCI's energy leveraged leases, see Note (4) to the consolidated financial statements of PHI set forth in Item 8 of this Form 10-K.

     Pepcom

     In December 2004, Pepcom sold its 50% interest in Starpower Communications, LLC (Starpower) for $29 million in cash to RCN Telecom Services of Washington, D.C., Inc., a wholly owned subsidiary of RCN

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Corporation which owned the other 50% interest in Starpower. Following the completion of the sale, Pepcom has no remaining investments.

EMPLOYEES

     As of December 31, 2004, PHI had 5,592 employees, including 1,606 employed by Pepco, 910 employed by DPL, 647 employed by ACE and 1,686 employed by PHI Service Company. The balance were employed by PHI's competitive energy and other non-regulated businesses.

ENVIRONMENTAL MATTERS

     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. PHI currently estimates that capital expenditures for environmental control facilities by its subsidiaries will be $6.6 million in 2005 and $5.7 million in 2006. However, the actual costs of environmental compliance may be materially different from these estimates depending on t he outcome of the matters addressed below or as a result of the imposition of additional environmental requirements or new or different interpretations of existing environmental laws and regulations.

     Air Quality Regulation

     The generation facilities and operations of PHI's subsidiaries are subject to federal, state and local laws and regulations, including the federal Clean Air Act (CAA), that limit emissions of air pollutants, require permits for operation of facilities and impose recordkeeping and reporting requirements.

     Among other things, the CAA regulates total sulfur dioxide (SO₂) emissions from affected generation units and allocates "allowances." The generation facilities of PHI's subsidiaries that require SO₂ allowances use allocated allowances or allowances acquired, as necessary, in the open market to satisfy applicable regulatory requirements. Also under current regulations implementing CAA standards, 22 eastern and mid-western states and the District of Columbia regulate nitrogen oxide (NOx) emissions from generation units and allocate NOx allowances. All of the generation units operated by PHI subsidiaries are subject to NOx emission limits and are required to hold, either through allocations or purchases, NOx allowances as necessary, to achieve compliance from May to September of each year.

     The New Jersey Department of Environmental Protection (NJDEP) administers CAA programs in New Jersey as well as air quality requirements imposed by New Jersey laws and regulations. In February 2000, the U.S. Environmental Protection Agency (EPA) and NJDEP requested information from ACE regarding the operation of coal-fired boilers at ACE's B.L. England facility and Conectiv Energy's (formerly ACE's) Deepwater facility to determine whether they were in compliance with the New Source Review (NSR), Prevention of Significant Deterioration (PSD) and non-attainment NSR requirements of the CAA. Generally, these regulations require that operators of major sources of certain air pollutants obtain permits, install

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pollution control technology and obtain offsets in some circumstances when those sources undergo a "major modification," as defined in the regulations. During 2002, ACE participated in preliminary discussions with EPA and NJDEP on this matter, without successful resolution.

     On October 27, 2003, EPA published a final rule clarifying the types of activities that qualify as "routine maintenance, repair and replacement" rather than "major modifications" and are therefore excluded from NSR requirements. A number of states, industrial entities and environmental groups have challenged the rule and the U.S. Court of Appeals for the District of Columbia Circuit has stayed the rule's applicability.

     PHI does not believe that any of its subsidiaries have violated NSR requirements, but cannot predict the consequences of the EPA/NJDEP inquiries on B.L. England or Deepwater generating plant operations.

     In an effort to address NJDEP's concerns regarding ACE's compliance with NSR requirements at the B.L. England generating facility, 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 alleged NSR liability, if any, at B.L. England and various other environmental issues involving ACE and Conectiv Energy facilities in New Jersey. While the preliminary settlement agreement does not resolve the EPA inquiry, it, among other things, provides that:

· 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 SO₂, 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 ev ent 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.

· 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 PSD provisions of the 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,

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	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 necessary to satisfy the EPA's new cooling water intake structure regulations in accordance with a schedule that NJDEP will establish in the New Jersey Pollutant Discharge Elimination System (NJPDES) renewal permit for the B.L. England facility. The schedule will take 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 also 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.

     On May 4, 2002, ACE and Conectiv Energy entered into an administrative consent order with NJDEP to address the inability of ACE and Conectiv Energy to procure Discrete Emission Reduction (DER) credits to comply fully with New Jersey's NOx Reasonably Available Control Technology requirements, as well as NJDEP's contention that ACE had failed to comply with DER credit use restrictions from 1996 to 2001. The administrative consent order (i) eliminated requirements for ACE and Conectiv Energy to purchase DER credits for certain generation units through May 1, 2005, (ii) provided for installation of new controls on certain Conectiv Energy electric generating units at an estimated cost of $10.7 million, (iii) imposed a $1 million penalty, (iv) required the contribution of $1 million to promote, develop and enhance an urban air shed reforestation project, and (v) imposed operating hour limits at Conectiv Energy's Deepwater generating facility Unit No . 4.

     In December 2003, the EPA proposed regulations under the CAA that would require reductions in emissions of mercury from coal-fired power plants and nickel from oil-fired power plants through implementation of Maximum Achievable Control Technology (MACT) standards. As an alternative, EPA proposed a "cap and trade" program for mercury emissions from coal-fired plants and limitations on nickel emissions from oil-fired plants. In addition, EPA's Clean Air Interstate rule, released on March 10, 2005, imposes additional reductions of SO₂ and NOx emissions from electric generating units in 28 Eastern states and the District of Columbia. These regulations may require installation of pollution control devices and/or fuel modifications for generating units owned by ACE, Conectiv Energy and Pepco Energy Services.

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     On December 6, 2004, NJDEP published final rules regulating mercury emissions from power plants and industrial facilities in New Jersey that impose standards that are significantly stricter than EPA's proposed mercury MACT standard for coal-fired plants. In lieu of meeting these standards for all New Jersey coal-fired units by December 15, 2007, NJDEP's final mercury rules allow an owner or operator to enter into an enforceable agreement to comply with the mercury limits for 50% of a company's total coal-fired capacity by the December 15, 2007 deadline and to comply with the mercury standards, as well as stringent standards regulating emissions of NOx, SO₂ and particulate matter, for the remaining 50% of its units by December 2012. Alternatively, if an owner or operator enters into an enforceable agreement with NJDEP by December 15, 2007 to shut down coal unit(s) by December 15, 2012, then the mercury limitations would not be appli cable to that particular unit. Contingent upon receipt of necessary approvals from the NJBPU, PJM, NERC/FERC and other regulatory authorities and the receipt of permits to construct certain transmission facilities in southern New Jersey, ACE plans to shut down the B.L. England generating facility by December 15, 2007. In this event, no significant capital improvements will be needed at B.L. England to comply with NJDEP's final mercury emission rules or any final EPA mercury rule that is promulgated. Conectiv Energy is investigating what, if any, capital or operational improvements are needed at the Deepwater generating facilityin order to comply with NJDEP's final mercury regulations and will analyze the need for capital or operational improvements at the Deepwater generating facility for compliance with EPA's mercury requirements after EPA promulgates a final rule. At this time, Conectiv Energy anticipates tha t activated carbon injection will be needed at Deepwater to meet these regulations at a cost of approximately $300,000.

     On June 29, 2004, New Jersey enacted legislation that imposes a tax on emissions of certain specifically identified toxic substances in New Jersey. In accordance with the legislation, an annual surcharge of $500,000 each will be imposed for ACE's B.L. England facility and for Conectiv Energy's Deepwater facility.

     On September 20, 2004, NJDEP proposed regulations regarding the further control of NOx emissions from combustion sources. These regulations would significantly reduce the NOx limit on B.L. England's diesel generators. These regulations, if adopted as proposed, may require the installation of pollution control devices on these units at a significant capital cost.

     On October 18, 2004, NJDEP proposed regulations that would classify carbon dioxide (CO₂) as an air contaminant and enable NJDEP potentially to regulate CO₂ emissions from power plants and other sources. These regulations, if adopted as proposed, could limit or control emissions of CO₂ from ACE and Conectiv Energy facilities in New Jersey in the future.

     Water Quality Regulation

     Section 402(a) of the federal Water Pollution Control Act, also known as the Clean Water Act (CWA), establishes the basic legal structure for regulating the discharge of pollutants from point sources to surface waters of the United States. Among other things, CWA Section 402(a) requires that any person wishing to discharge pollutants from a point source (generally a confined, discrete conveyance such as a pipe) obtain a National Pollutant Discharge Elimination System (NPDES) permit issued by the EPA or by a state agency under a federally authorized state program. All of the steam generation facilities operated by PHI's subsidiaries have NPDES permits authorizing their pollutant discharges.

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     On July 9, 2004, the EPA issued final regulations under Section 316(b) of the CWA that are intended to minimize potential adverse environmental impacts from power plant cooling water intake structures on aquatic resources by establishing performance-based standards for the operation of these structures at large existing electric generating plants. These regulations may require changes to cooling water intake structures at facilities operated by ACE, Conectiv Energy and Pepco Energy Services. However, the capital expenditures the regulations will require at each facility, if any, will not be known until each facility completes various studies in accordance with a schedule to be established in each permit. Based on these studies, the applicable permitting authority will specify any changes to cooling water intake structures that are required in a facility's NPDES renewal permit.

     The EPA has delegated authority to administer the NPDES program to a number of state agencies including the Delaware Department of Natural Resources and Environmental Control (DNREC). The NPDES permit for Conectiv Energy's Edge Moor Power Plant expired on October 30, 2003, but has been administratively extended through the submission of a renewal application to the DNREC in April 2003. Studies required under the existing permit to determine the impact on aquatic organisms of the plant's cooling water intake structures were completed in 2002. Site-specific alternative technology and operational studies are being conducted to determine the extent of expenditures necessary to modify cooling water intake structures in order to comply with EPA's CWA Section 316(b) performance-based standards. PHI cannot predict the extent of these expenditures until the site-specific studies are completed.

     Under the New Jersey Water Pollution Control Act, NJDEP implements regulations, administers the NJPDES program with EPA oversight, and issues and enforces NJPDES permits. The NJPDES renewal permit for Conectiv Energy's Deepwater generating facility, effective through September 30, 2007, requires several studies to determine whether or not Deepwater's cooling water intake structures are protective of the environment. The studies required by Deepwater's NPDES permit are consistent with requirements under EPA's regulations implementing CWA Section 316(b). NJDEP will consider the results of these studies, as well as other related information submitted in accordance with EPA's CWA Section 316(b) regulations, in connection with the facility's NJPDES permit renewal application, which will be filed in 2007.

     The renewal NJPDES permit for the B.L. England generating facility was issued by NJDEP on February 24, 2005. Consistent with EPA's CWA Section 316(b) regulations, B.L. England's renewal permit requires ACE to submit a Proposal for Information Collection by September 7, 2005 and complete a Comprehensive Demonstration Study within three and one-half years. In addressing CWA Section 316(b) requirements for B.L. England, the April 26, 2004 preliminary settlement agreement with NJDEP provides that ACE will submit all federally required studies and complete construction of all facilities necessary to satisfy the EPA's new cooling water intake structure regulations in accordance with a schedule established by the NJDEP in the renewal of the NJPDES permit for the B.L. England facility. The NJDEP will take into account ACE's agreement to shut down the B.L. England facility by December 15, 2007, subject to receipt of all regulatory approvals.

     Pepco and a subsidiary of Pepco Energy Services discharge water from a steam generation plant and service center located in the District of Columbia under a NPDES permit issued by EPA in November 2000. Pepco has

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filed a petition with the EPA Environmental Appeals Board seeking review and reconsideration of certain provisions of EPA's permit determination. In May 2001, Pepco and EPA reached a settlement on Pepco's petition, under which EPA withdrew certain contested provisions and agreed to issue a revised draft permit for public comment. The EPA has not issued the revised draft permit and the companies are operating under the November 2000 permit, excluding the withdrawn conditions, in accordance with the settlement agreement.

     Hazardous Substance Regulation

     The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), authorizes the EPA, and comparable state laws authorize state environmental authorities, to issue orders and bring enforcement actions to compel responsible parties to investigate and take remedial actions at any site that is determined to present an actual or potential threat to human health or the environment because of an actual or threatened release of one or more hazardous substances. Parties that generated or transported hazardous substances to such sites, as well as the owners and operators of such sites, may be deemed liable under CERCLA or comparable state laws. Pepco, DPL and ACE each has been named by the EPA or a state environmental agency as a potentially responsible party (PRP) at certain contaminated sites. See Item 3 -- "Legal Proceedings -- Environmental Litigation." In addition, DPL and ACE have undertaken efforts to remediate curren tly or formerly owned facilities found to be contaminated, including two former manufactured gas plant sites and other owned property. See Item 3 -- "Legal Proceedings -- Environmental Litigation" and Item 7 -- "Management's Discussion and Analysis -- Capital Resources and Liquidity -- Capital Requirements -- Environmental Remediation Obligations."

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Item 2.     PROPERTIES

Generation Facilities

     The following table identifies the electric generation facilities owned by PHI's subsidiaries.

Electric Generating Facilities		Location	Owner	Generating Capacity  (kilowatts)
Coal-Fired
	Edge Moor	Wilmington, DE	Conectiv Energy1	260,000
	B L England	Beesley's Pt., NJ	ACE	284,000
	Conemaugh2	New Florence, PA	ACE	65,000
	Keystone3	Shelocta, PA	ACE	42,000
	Deepwater4	Pennsville, NJ	Conectiv Energy1	80,000
				731,000
Oil Fired
	Benning Road	Washington, DC	Pepco Energy Services	550,000
	Edge Moor	Wilmington, DE	Conectiv Energy1	445,000
	B L England	Beesley's Pt., NJ	ACE	155,000
	Deepwater4	Pennsville, NJ	Conectiv Energy1	86,000
				1,236,000
Combustion Turbines/Combined Cycle
	Hay Road Units 1-45	Wilmington, DE	Conectiv Energy1	521,000
	Hay Road Units 5-8	Wilmington, DE	Conectiv Energy1	545,000
	Bethlehem Units 1-8	Bethlehem, PA	Conectiv Energy1	1,092,000
	Buzzard Point	Washington, DC	Pepco Energy Services	256,000
	Cumberland	Millville, NJ	Conectiv Energy1	84,000
	Sherman Avenue	Vineland, NJ	Conectiv Energy1	81,000
	Middle	Rio Grande, NJ	Conectiv Energy1	77,000
	Carll's Corner	Upper Deerfield Twp., NJ	Conectiv Energy1	73,000
	Cedar	Cedar Run, NJ	Conectiv Energy1	68,000
	Missouri Avenue	Atlantic City, NJ	Conectiv Energy1	60,000
	Mickleton	Mickleton, NJ	Conectiv Energy1	59,000
	Christiana	Wilmington, DE	Conectiv Energy1	45,000
	Deepwater4	Pennsville, NJ	Conectiv Energy	19,000
	Edge Moor	Wilmington, DE	Conectiv Energy1	13,000
	Madison Street6	Wilmington, DE	Conectiv Energy	11,000
	West	Marshallton, DE	Conectiv Energy1	15,000
	Delaware City	Delaware City, DE	Conectiv Energy1	16,000
	Tasley	Tasley, VA	Conectiv Energy1	26,000
				3,061,000
Diesel Units
	Crisfield	Crisfield, MD	Conectiv Energy1	10,000
	Bayview	Bayview, VA	Conectiv Energy1	12,000
	B L England	Beesley's Pt., NJ	ACE	8,000
	Keystone3	Shelocta, PA	ACE	300
	Conemaugh2	New Florence, PA	ACE	400
				30,700
Total Electric Generating Capacity				5,058,700
1  All holdings of Conectiv Energy are owned by its various subsidiaries.
2  ACE holds a 3.83% undivided interest as a tenant in common.
3  ACE holds a 2.47% undivided interest as a tenant in common.
4  Transferred by ACE to Conectiv Energy as of March 1, 2004.
5  Effective January 9, 2005, the capacity of Hay Road Units 1-4      has been increased to 540,000.
6  Effective January 1, 2005, the Madison Street CT has been retired.

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     The above table sets forth the summer electric generating capacity of the electric generating plants owned by Pepco Holdings' subsidiaries. Although, due to thermoelectric factors, the generating capacity of these facilities may be higher during the winter months, the plants operated by PHI's subsidiaries are used to meet summer peak loads that are generally higher than winter peak loads. Accordingly, the summer generating capacity more accurately reflects the operational capability of the plants.

     ACE's generation facilities are subject to the lien of the mortgage under which its First Mortgage Bonds are issued.

Transmission and Distribution Systems

     On a combined basis, the electric transmission and distribution systems owned by Pepco, DPL and ACE at December 31, 2004 consisted of approximately 3,502 transmission circuit miles of overhead lines, 155 transmission circuit miles of underground cables, 22,686 distribution circuit miles of overhead lines, and 18,649 distribution circuit miles of underground cables, primarily in their respective service territories. Pepco also operates a distribution system control center in Maryland. The computer equipment and systems contained in the control center are financed through a sale and leaseback transaction.

     DPL has a liquefied natural gas plant located in Wilmington, Delaware, with a storage capacity of 3,045 million gallons and an emergency sendout capability of 45,000 Mcf per day. DPL owns eight natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total sendout capacity of 225,000 Mcf per day. DPL also owns approximately 111 pipeline miles of gas transmission mains, 1,728 pipeline miles of gas distribution mains, and 1,268gas pipeline miles of service lines. The gas transmission mains include 7.2 miles of pipeline of which DPL owns 10% which is used for gas operations and Conectiv Energy owns 90% which is used for delivery of gas to electric generation facilities.

     Substantially all of the transmission and distribution property, plant and equipment owned by each of Pepco, DPL and ACE are subject to the liens of the respective mortgages under which the companies issue First Mortgage Bonds. See Note (7) to the consolidated financial statements of PHI set forth in Item 8 of this Form 10-K.

Item 3.    LEGAL PROCEEDINGS

Pepco Holdings

     The legal proceedings for Pepco Holdings consist solely of those of its subsidiaries, as described below.

GENERAL LITIGATION

Pepco

     Asbestos

     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

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brought into these cases on a theory of premises liability. Under this theory, plaintiffs argue 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.

DPL and Conectiv Energy

     Enron

     On December 2, 2001, Enron North America Corp. and several of its affiliates (collectively, Enron) filed for protection under the United States Bankruptcy Code. In December 2001, DPL and Conectiv Energy terminated all energy trading transactions under various agreements with Enron. In late January 2003, after several months of discussions between the parties concerning the amount owed by DPL and Conectiv Energy, Enron filed an adversary complaint against Conectiv Energy in the Bankruptcy Court for the Southern District of New York. The complaint sought, among other things, damages in the amount of approximately $11.7 million.

     On June 3, 2004, the Bankruptcy Court approved a settlement among Enron, Conectiv Energy and DPL pursuant to which Conectiv Energy paid Enron an agreed settlement amount that was less than the $11.7 million damages Enron sought and the parties released all claims against each other. Conectiv Energy had previously established a reserve in an amount equal to the agreed settlement payment. Accordingly, the settlement did not have an effect on earnings.

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

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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.

Pepco and DPL

     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 CERCLA at the Diamond State Salvage site in Wilmington, Delaware. In the context of the negotiations, DOJ informed DPL that DPL is a de minimis party at the site. In February 2005, DPL entered into a de minimis consent decree with the United States which, if approved by the U.S. District Court, would require DPL to pay $144,000 as reimbursement of the government's response costs, resolve DPL's alleged liability, and provide DPL a covenant not to sue from the United States and protection from third-party claims for contribution.

     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. DPL expects to complete the RI/FS in the first quarter of 2005.

     In October 1995, each of Pepco and DPL received notice from EPA that it, along with several hundred other companies, might be a 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 this site. Under the terms of the consent decree, which was approved by the U.S. District Court for the District of Maryland on March 31, 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 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.

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     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. On May 12, 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. On October 2, 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 December 31, 2004, Pepco had accrued $1.7 million to meet its liability for a site remedy. 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.

     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 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.

     On April 7, 2000, approximately 139,000 gallons of oil leaked from a pipeline at a generation station that was owned by Pepco at Chalk Point Generating Station in Aquasco, Maryland. The pipeline was operated by Support Terminals Services Operating Partnership LP (ST Services), an unaffiliated pipeline management company. The oil spread from Swanson Creek to the Patuxent River and several of its tributaries. The area affected covers portions of 17 miles of shoreline along the Patuxent River and approximately 45 acres of marshland adjacent to the Chalk Point property.

     In December 2000, the Department of Transportation, Office of Pipeline Safety, Research and Special Programs Administration (OPS) issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (NOPV). The NOPV alleged various deficiencies in compliance with regulations related to spill reporting, operations and maintenance of the pipeline and record keeping, none of which relate to the cause of the spill. The NOPV was issued to both Pepco and ST Services and proposed a civil penalty in the amount of $674,000. On June 2, 2004, the OPS issued a Final Order regarding the NOPV in this matter. The Final Order assessed a total fine of $330,250, with $256,250 of that amount assessed jointly against Pepco and ST Services and the remaining $74,000 assessed solely against ST Services. ST Services subsequently filed a Petition for Reconsideration. All penalties were stayed pending the outcome of the Petition for Rec onsideration. On February 9, 2005, OPS issued a Decision on the Petition for Reconsideration that affirmed the Final Order. Pepco's share of the $330,250 penalty assessed pursuant to the Final Order amounts to $128,125.

ACE

     In June 1992, 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

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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.

     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:

· contingent upon the receipt of necessary approvals from the NJBPU, PJM, 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 SO₂, 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 re quired 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. Englandgenerating 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.

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· to resolve any possible civil liability (and without admitting liability) for violations of the permit provisions of the New Jersey APCA and the PSD provisions of the 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 necessary to satisfy the EPA's new cooling water intake structure regulations in accordance with a schedule that NJDEP will establish in the renewal NJPDES permit for the B.L. England facility. The schedule will take 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 also 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.

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

Pepco Holdings - None.

Pepco - None.

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

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Part II

Item 5.    MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER
           MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

     The New York Stock Exchange is the principal market on which Pepco Holdings common stock is traded. The following table presents the dividends declared per share on the Pepco Holdings common stock and the high and low sales prices for common stock as reported by the New York Stock Exchange during each quarter in the last two fiscal years.

Period	Dividends     Per Share	Price Range    High         Low
2004:
First Quarter	$ .25	$21.71	$19.08
Second Quarter	.25	20.70	16.94
Third Quarter	.25	20.70	17.90
Fourth Quarter	.25	21.68	19.88
	$1.00
2003:
First Quarter	$ .25	$20.56	$16.73
Second Quarter	.25	20.51	16.10
Third Quarter	.25	19.65	16.65
Fourth Quarter	.25	19.84	17.28
	$1.00

     See Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Capital Resources and Liquidity" for information regarding restrictions on the ability of PHI and its subsidiaries to pay dividends.

     At December 31, 2004, there were approximately 75,674 holders of record of the Pepco Holdings common stock.

PHI Subsidiaries

     Pepco, DPL and ACE each customarily pays dividends on its common stock on a quarterly basis based on its earnings, cash flow and capital structure, and after taking into account the business plans and financial requirements of PHI and its other subsidiaries.

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     Pepco

     All of Pepco's common stock is held by Pepco Holdings. The table below presents the aggregate amount of common stock dividends paid by Pepco to PHI during the periods indicated.

Period	Aggregate Dividends
2004:
First Quarter	$ 11,832,000
Second Quarter	30,329,000
Third Quarter	52,532,000
Fourth Quarter	7,697,000
	$102,390,000
2003:
First Quarter	$ 15,720,000
Second Quarter	31,342,000
Third Quarter	15,000,000
Fourth Quarter	2,900,000
	$ 64,962,000

     DPL

     All of DPL's common stock is held by Conectiv. The table below presents the aggregate amount of common stock dividends paid by DPL to Conectiv during the periods indicated.

Period	Aggregate Dividends
2004:
First Quarter	$22,067,000
Second Quarter	22,393,000
Third Quarter	13,693,000
Fourth Quarter	9,845,000
	$67,998,000
2003:
First Quarter	$18,577,000
Second Quarter	9,116,000
Third Quarter	11,888,000
Fourth Quarter	9,507,000
	$49,088,000

     ACE

     All of ACE's common stock is held by Conectiv. The table below presents the aggregate amount of common stock dividends paid by ACE to Conectiv during the periods indicated.

Period	Aggregate Dividends
2004:
First Quarter	$ 5,647,000
Second Quarter	-
Third Quarter	-
Fourth Quarter	4,973,000
	$10,620,000
2003:
First Quarter	$ 8,224,000
Second Quarter	14,458,000
Third Quarter	18,800,000
Fourth Quarter	-
	$41,482,000

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(c)   Purchases of Equity Securities by the Issuer and Affiliated Purchasers.

Pepco Holdings

     None.

Pepco

     The following table summarizes the activity related to repurchases of Pepco's equity securities during the quarter ended December 31, 2004:

PURCHASES OF EQUITY SECURITIES
Period	Total Number of Shares (or Units)Purchased	Average Price Paid per Share(or Unit)	Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plansor Programs	Maximum Number (or Approximate Dollar Value) that May Yet Be Purchased Under the Plans orPrograms
October 1-31, 2004	84,5021 shares of $2.28 Preferred, Series 1965	$47.02	N/A	N/A
November 1-30, 2004	0	N/A	N/A	N/A
December 1-31, 2004	850,0002 shares of $3.40 Preferred, Series 1992	$50.00	N/A	N/A
Total	934,502	$49.7305	N/A	N/A
1Purchased in privately negotiated transactions
2Redeemed pursuant to provisions of preferred stock

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

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Item 6.    SELECTED FINANCIAL DATA
PEPCO HOLDINGS CONSOLIDATED FINANCIAL HIGHLIGHTS
		2004		2003		2002 (a)	2001		2000
		(In Millions, except Per Share Data)
Consolidated Operating Results
Total Operating Revenue	$	7,221.8		7,271.3		4,324.5	2,371.2		2,989.3	(g)
Total Operating Expenses	$	6,446.1		6,654.9	(c)	3,778.9	2,004.8	(f)	2,094.2
Operating Income	$	775.7		616.4		545.6	366.4		895.1
Other Expenses	$	341.0		429.0	(d)	190.4	105.3		192.7
Preferred Stock Dividend   Requirements of Subsidiaries	$	2.8		13.9		20.6	14.2		14.7
Income Before Income Tax Expense	$	431.9		173.5		334.6	246.9		687.7
Income Tax Expense	$	173.2	(b)	65.9		124.1	83.5		341.2
Income Before Extraordinary Item	$	258.7		107.6		210.5	163.4		346.5
Extraordinary Item	$	-		5.9		-	-		-
Net Income	$	258.7		113.5	(e)	210.5	163.4		346.5
Redemption Premium on   Preferred Stock	$	0.5		-		- -	- -		- -
Earnings Available for   Common Stock	$	259.2		113.5		210.5	163.4		346.5
Common Stock Information
Basic Earnings Per Share of Common   Stock Before Extraordinary Item	$	1.47		.63		1.61	1.51		3.02
Basic - Extraordinary Item Per   Share of Common Stock	$	-		.03		-	-		-
Basic Earnings Per Share   of Common Stock	$	1.47		.66		1.61	1.51		3.02
Diluted Earnings Per Share   of Common Stock Before   Extraordinary Item	$	1.47		.63		1.61	1.50		2.96
Diluted - Extraordinary Item Per   Share of Common Stock	$	-		.03		-	-		-
Diluted Earnings Per Share   of Common Stock	$	1.47		.66		1.61	1.50		2.96
Basic Common Shares Outstanding   (Average)		176.8		170.7		131.1	108.5		114.9
Diluted Common Shares Outstanding   (Average)		176.8		170.7		131.1	108.8		118.3
Cash Dividends Per Share   of Common Stock	$	1.00		1.00		1.00	1.165		1.66
Year-End Stock Price	$	21.32		19.54		19.39	22.57		24.71
Book Value per Common Share	$	17.88		17.48		17.62	17.00		16.82
Other Information
Investment in Property, Plant   and Equipment	$	11,045.2		10,747.2		10,625.0	4,361.9		4,284.7
Net Investment in Property, Plant   and Equipment	$	7,088.0		6,964.9		7,043.3	2,819.0		2,786.5
Total Assets	$	13,349.4		13,371.3		13,404.1	5,395.7		7,209.7
Capitalization (SEC/PUHCA Method)
Short-term Debt (h)	$	161.3		360.0		812.7	350.2		211.6
Long-term Debt (i)	$	5,554.7		5,678.5		5,277.5	1,710.1		2,674.8
Project funding (j)	$	70.7		73.6		30.4	22.9		19.4
Debentures issued to   Financing Trust (k)	$	-		98.0		-	-		-
Trust Preferred Securities (l)	$	-		-		290.0	125.0		125.0
Preferred Stock (m)	$	54.9		108.2		110.7	84.8		90.3
Shareholders' Equity	$	3,366.3		3,003.3		2,995.8	1,823.2		1,862.5
Total Capitalization	$	9,207.9		9,321.6		9,517.1	4,116.2		4,983.6

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(a)	As a result of the acquisition of Conectiv by Pepco that was completed on August 1, 2002, PHI's 2004 and 2003 amounts include PHI and its subsidiaries' results for the full year. PHI's 2002 amounts include Conectiv and its subsidiaries post-August 1, 2002 results with Pepco and its pre-merger subsidiaries (PCI and Pepco Energy Services) results for all of 2002. The amounts presented for 2001 and 2000 represent only Pepco and its pre-merger subsidiaries results. For additional information, refer to the Management's Discussion and Analysis of Financial Condition and Results of Operations section, herein.
(b)	Includes a $19.7 million charge related to an IRS settlement.
(c)	Includes a charge of $50.1 million ($29.5 million after-tax) related to a CT contract cancellation. Also includes a gain of $68.8 million ($44.7 million after-tax) on the sale of the Edison Place office building.
(d)	Includes an impairment charge of $102.6 million ($66.7 million after-tax) related to Pepcom's investment in Starpower Communications, LLC.
(e)	Includes the unfavorable impact of $44.3 million ($26.6 million after-tax) resulting from trading losses prior to the cessation of proprietary trading.
(f)	Includes $55.5 million ($36.1 million after-tax) impairment charge related to the write-down of aircraft leasing portfolio.
(g)	Includes $423.8 million ($182.0 million after-tax) gain on sale of Pepco's Generation Assets to Mirant.
(h)	Excludes current maturities of long-term debt, capital lease obligations due within one year, and Variable Rate Demand Bonds.
(i)	Includes 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.
(j)	Represents funding for energy savings contracts performed by Pepco Energy Services and includes current portion of project funds that were provided in exchange for the sale of the customers' accounts receivable.
(k)	Represents debentures issued to Financing Trust and current portion of debentures issued to Financing Trust.
(l)	Company obligated mandatorily redeemable preferred securities of subsidiary trust which holds solely parent junior subordinated debentures.
(m)	Represents Mandatorily Redeemable Serial Preferred Stock, Serial Preferred Stock, and Redeemable Serial Preferred Stock.

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PEPCO CONSOLIDATED FINANCIAL HIGHLIGHTS
		2004	2003	2002 (a)	2001		2000
	(In Millions, except Per Share Data)
Consolidated Operating Results
Total Operating Revenue	$	1,805.9	1,548.0	1,988.0	2,371.2		2,989.3	(c)
Total Operating Expenses	$	1,579.7	1,298.9	1,663.1	2,004.8	(b)	2,094.2
Operating Income	$	226.2	249.1	324.9	366.4		895.1
Other Expenses	$	72.9	70.8	96.3	105.3		192.7
Distributions on Preferred   Securities of Subsidiary Trust	$	-	4.6	9.2	9.2		9.2
Income Before Income Tax Expense	$	153.3	173.7	219.4	251.9		693.2
Income Tax Expense	$	56.7	69.1	80.3	83.5		341.2
Net Income	$	96.6	104.6	139.1	168.4		352.0
Dividends on Preferred Stock	$	1.0	3.3	5.0	5.0		5.5
Earnings Available for Common Stock	$	95.6	101.3	134.1	163.4		346.5
Common Stock Information
Basic Earnings Per Share   of Common Stock	$	-	-	-	1.51		3.02
Diluted Earnings Per Share   of Common Stock	$	-	-	-	1.50		2.96
Basic Common Shares Outstanding   (Average)		-	-	-	108.5		114.9
Diluted Common Shares Outstanding   (Average)		-	-	-	108.8		118.3
Cash Dividends Per Share   of Common Stock	$	-	-	1.00	1.165		1.66
Year-End Stock Price	$	-	-	-	22.57		24.71
Book Value per Common Share	$	-	-	-	17.00		16.82
Other Information
Investment in Property, Plant   and Equipment	$	4,869.4	4,694.5	4,550.0	4,361.9		4,284.7
Net Investment in Property, Plant   and Equipment	$	2,931.6	2,924.9	2,882.4	2,819.0		2,786.5
Total Assets	$	3,703.8	3,670.0	3,723.3	5,395.7		7,209.7
Capitalization (SEC/PUHCA Method)
Short-term Debt (d)	$	14.0	107.5	40.0	350.2		211.6
Long-term Debt (e)	$	1,298.3	1,130.4	1,133.5	1,710.1		2,674.8
Trust Preferred Securities (f)	$	-	-	125.0	125.0		125.0
Preferred Stock (g)	$	27.0	80.3	82.8	84.8		90.3
Shareholders' Equity	$	1,002.7	1,011.8	975.4	1,823.2		1,862.5
Total Capitalization	$	2,342.0	2,330.0	2,356.7	4,093.3		4,964.2

(a)	On August 1, 2002 ownership of Pepco's pre-merger subsidiaries (PCI and Pepco Energy Services) was transferred to Pepco Holdings. For additional information, refer to the Management's Discussion and Analysis of Financial Condition and Results of Operations section, herein.
(b)	Includes $55.5 million ($36.1 million after-tax) impairment charge related to the write-down of aircraft leasing portfolio.
(c)	Includes $423.8 million ($182.0 million after-tax) gain on sale of Pepco's Generation Assets to Mirant.
(d)	Excludes current maturities of long-term debt and capital lease obligations due within one year.
(e)	Excludes capital lease obligations but includes current maturities of long-term debt.
(f)	Company obligated mandatorily redeemable preferred securities of subsidiary trust which holds solely parent junior subordinated debentures.
(g)	Represents Mandatorily Redeemable Serial Preferred Stock, Serial Preferred Stock, and Redeemable Serial Preferred Stock.

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

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Item 7.    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	34
Pepco	99
DPL	129
ACE	138

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THIS PAGE LEFT INTENTIONALLY BLANK.

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

PEPCO HOLDINGS, INC.

GENERAL OVERVIEW

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

· electricity and natural gas delivery ("Power Delivery"),

· competitive energy generation, marketing and supply ("Competitive Energy"), and

· other activities consisting primarily of investments in energy-related assets ("Other Non-regulated").

     ThePower Deliverybusinessis the largest component PHI's business. In 2004, Power Delivery was responsible for 61% of PHI's consolidated operating revenues and 70% of its consolidated operating income. The Power Delivery business consists primarily of the transmission and distribution of electric power, which was responsible for 95% of Power Delivery 2004 revenues, and the distribution of natural gas, which contributed 5% of Power Delivery 2004 revenues.

     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 compose 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 provides default electricity supply to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier for which it is compensated at regulated rates. The rates each company is permitted to charge for the transmission of electricity is regulated by FERC. This means that the profitability of the Power Delivery business depends on its ability through the rates it is permitted to charge to recover costs and earn a reasonable return on its capital investments.

     Power Delivery's operating revenue and income are seasonal, and weather patterns may have a material impact on operating results. Historically, Power Delivery operations have generated less revenue and income when weather conditions are milder in the winter and cooler in the summer.

     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 Conectiv Energy and Pepco Energy Services, each of which is treated as a separate business segment for financial reporting purposes. In 2004, theCompetitive Energy segment, including intercompany transactions, was responsible for 50% of PHI's consolidated operating revenues and 19% of its consolidated operating income. Of this segment's operating revenues, 8% of PHI's consolidated operating revenues were attributable to sales to the Power Delivery segment.

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· Conectiv Energy provides wholesale power, capacity and ancillary services in the wholesale markets administered by PJM and also supplies electricity to other wholesale market participants under long-term bilateral contracts. 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 that ACE acquires for its distribution customers. 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 primarily in the mid-Atlantic region and provides integrated energy management services. 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. 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.

     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. This hedging strategy is more fully discussed in Item 1. Business.

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

     The Other Non-Regulated business has been conducted primarily through two subsidiaries of PHI:

· Potomac Capital Investment Corporation ("PCI") manages an existing portfolio of financial investments primarily consisting of energy leveraged leases. During the second quarter of 2003 PCI discontinued all new investment activities.

· Pepco Communications, Inc. ("Pepcom"), which in December 2004, sold its only asset, a 50% membership interest in Starpower Communications, LLC ("Starpower"), a joint venture with RCN Corporation (RCN), to RCN for $29 million in cash.

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     PHI does not plan to make further investments in its Other Non-Regulated businesses, and will focus on maintaining the earnings stream from its energy leveraged leases. For a discussion of certain tax and accounting issues associated with PCI's leveraged lease portfolio, see "Regulatory and Other Matters," herein.

BUSINESS STRATEGY

     PHI's business strategy has three primary components:

· Achieving stable earnings in the Power Delivery business by focusing on the delivery of energy in a cost effective manner, while maintaining a high level of service reliability and customer satisfaction.

· Supplementing PHI's utility earnings through complementary energy businesses that focus primarily on serving the competitive wholesale and retail markets in PJM. These businesses use conservative risk management practices to manage their commodity price and volume exposures. In addition, Conectiv Energy matches its portfolio of generation assets with its wholesale energy supply load.

· Strengthening PHI's credit profile through active debt reduction efforts.

EARNINGS OVERVIEW

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003 Results

     PHI's net income for the year ended December 31, 2004 was $258.7 million, or $1.47 per share, compared to $113.5 million, or $0.66 per share, for the year ended December 31, 2003. 2004 net income included the charges and credits set forth below (which are presented net of tax and in millions of dollars). The segment that recognized the charge or credit also (or, if not attributable to a segment, Corporate and Other) is indicated.

· $(7.3) charge to reduce the book value of PHI's 50% Starpower investment to $28 million which was sold to RCN in December 2004 - Other Non-Regulated

· 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. Effect by segment is:

Power Delivery	$ 0.8
Pepco Energy Services	1.5
Other Non-Regulated	8.8
Corporate & Other	2.1
PHI Consolidated	$13.2

· $6.6 gain on disposition associated with Vineland Cogeneration facility - Conectiv Energy

· $(7.7) impact of expenses associated with the prepayment of the Bethlehem debt - Conectiv Energy

· $8.6 gain on the disposition of Vineland distribution assets - Power Delivery

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· $(19.7) charge resulting from a tax settlement with the IRS related to PCI's non-lease financial assets - Other Non-Regulated

· An aggregate of $(7.7) in severance costs accruals. Effect by segment is:

Power Delivery	$(2.2)
Conectiv Energy	(0.5)
Other Non-Regulated	(0.2)
Corporate & Other	(4.8)
	$(7.7)

     Net income for 2003 included the charges and credits set forth below (which are presented net of tax and in millions of dollars). The segment that recognized the charge and credit also is indicated.

· $(66.7) charge in the fourth quarter of 2003 to reduce the book value of PHI's 50% equity interest in Starpower - Other Non-Regulated

· $(26.6) unfavorable impact resulting from net trading losses prior to the cessation of proprietary trading - Conectiv Energy

· Unfavorable impact related to the cancellation of a contract to purchase combustion turbines of $(64.1) at Conectiv Energy, offset by a $34.6 reversal of a purchase accounting fair value adjustment made on the date of the Pepco/Conectiv merger for Corporate and Other

· $(16.3) charge resulting from ACE's New Jersey deferral disallowance - Power Delivery

· $5.9 credit resulting from a reversal of a reserve for stranded costs at ACE - Power Delivery

· $(8.7) reserve recorded against a pre-petition receivable from Mirant - Power Delivery

· $(19.4) impairment of combustion turbine inventory at Conectiv Energy, offset by a $17.7 reversal of a purchase accounting fair value adjustment made on the date of Pepco's acquisition of Conectiv - Corporate & Other

· $44.7 gain on the sale of Edison Place office building - Other Non-Regulated

     Excluding the items listed above, net income would have been $272.6 million in 2004 and net income in 2003 would have been $212.4 million. This increase in 2004 compared to 2003 was primarily due to: higher earnings for Conectiv Energy from its merchant generation plants; higher earnings for Pepco Energy Services as a result of improved margins from its retail commodity business and higher earnings for Other Non-Regulated due to sales of aircraft and lower interest expense.

SEGMENT RESULTS

     Set forth below is a summary of the principal factors contributing to the earnings variances between the year ended December 31, 2004, compared to December 31, 2003 (net of tax and in millions of dollars):

Power Delivery

· $26.5 of lower earnings primarily as a result of the TPA settlement with Mirant in October 2003

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· $16.9 of higher regulated T&D revenue as a result of 2% electric sales growth of $13.9 and more favorable summer weather of $3.0

· $4.9 of lower depreciation and other taxes

· $2.7 of higher earnings related to lower interest expense, partially offset by higher operations and maintenance and other miscellaneous expenses

Conectiv Energy

· $34.1 of higher merchant generation earnings, which resulted primarily from fuel switching, hedging and use of power plant flexibility

· $9.5 of higher earnings from Provider of Last Resort (POLR) services as a result of an increase in average sales prices and somewhat lower purchased power costs

· $14.5 lower earnings primarily due to lower capitalized interest and higher depreciation expense as a result of the completion of Bethlehem facility and higher effective tax rate

Pepco Energy Services

· $8.5 increase in earnings primarily from its retail commodity business

Other Non-Regulated

· $5.4 of gains on the sale of PCI's last remaining aircraft leases

· $9.1 of primarily lower interest expense

Corporate and Other

· $2.4 gain on the sale of a note receivable relating to a previous asset disposition

· $4.5 of lower amortization

· $3.1 of other positive miscellaneous items, including lower taxes

CONSOLIDATED RESULTS OF OPERATIONS

     The results of operations discussion below is for the year ended December 31, 2004 compared to the year ended December 31, 2003. All amounts in the tables (except customers) include intercompany transactions and are in millions.

Operating Revenue

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

	2004	2003	Change
Power Delivery	$4,375.9	$4,016.8	$359.1
Conectiv Energy	2,408.3	2,859.0	(450.7)
Pepco Energy Services	1,168.6	1,126.2	42.4
Other Non-Regulated	87.9	100.1	(12.2)
Corporate and Other	(818.9)	(830.8)	11.9
Total Operating Revenue	$7,221.8	$7,271.3	$(49.5)

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     Power Delivery Business

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

	2004	2003	Change
Regulated T&D Electric Revenue	$1,566.7	$1,521.0	$45.7
Default Supply Revenue	2,514.7	2,206.1	308.6
Other Electric Revenue	66.8	98.7	(31.9)
Total Electric Operating Revenue	4,148.2	3,825.8	322.4
Regulated Gas Revenue	169.1	150.2	18.9
Other Gas Revenue	58.6	40.8	17.8
Total Gas Operating Revenue	227.7	191.0	36.7
Total Power Delivery Operating Revenue	$4,375.9	$4,016.8	$359.1

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

     Default Supply Revenue (DSR) also known, depending on the jurisdiction as Standard Offer Service (SOS), Basic Generation Service (BGS), and Provider of Last Resort (POLR) consists of revenue received from the supply of electricity within PHI's service territories at regulated rates pursuant to supply obligations. 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 revenues from the transportation of natural gas and on-system gas sales to customers within PHI's service territories at regulated rates.

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

     Electric Operating Revenue

Regulated T&D Electric Revenue	2004	2003	Change
Residential	$  598.6	$  576.2	$22.4
Commercial	715.2	674.7	40.5
Industrial	37.3	41.0	(3.7)
Other - PJM	215.6	229.1	(13.5)
Total Regulated T&D Electric Revenue	$1,566.7	$1,521.0	$45.7

Regulated T&D Electric Sales (KwH)	2004	2003	Change
Residential	17,780	17,147	633
Commercial	28,440	27,648	792
Industrial	4,458	4,874	(416)
Total Regulated T&D Electric Sales	50,678	49,669	1,009

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Regulated T&D Electric Customers (000s)	2004	2003	Change
Residential	1,567	1,547	20
Commercial	193	191	2
Industrial	2	2	-
Total Regulated T&D Electric Customers	1,762	1,740	22

     The ACE, DPL, and Pepco service territories are located within the Washington, DC to southern New Jersey corridor. These service territories taken together are economically diverse and include key industries that contribute to the regional economic base and to PHI's growing T&D revenues.

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

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

     Regulated T&D Electric Sales, as measured on a KwH basis, increased by 2% in 2004, driven by residential and commercial customer classes. Regulated T&D Revenue increased by $45.7 million primarily due to the following: (i) $14.4 million increase due to growth and average customer usage, (ii) $4.8 million increase due to higher average effective rates, (iii) $9.1 million favorable weather, (iv) $39.9 million increase in tax pass-throughs, principally a county surcharge, (offset in Other Taxes). These increases were offset by (v) $20.5 million decrease primarily related to PJM network transmission revenue and the impact of customer choice and (vi) $2.1 million related to Delaware competitive transition charge that ended in 2003. Cooling degree days increased by 11.0% and heating degree days decreased by 6.3% for the year ended December 31, 2004 as compared to the same period in 2003.

Default Supply Revenue	2004	2003	Change
Residential	$  993.6	$  875.2	$118.4
Commercial	1,069.3	946.4	122.9
Industrial	140.2	156.1	(15.9)
Other (Includes PJM)	311.6	228.4	83.2
Total Default Supply Revenue	$2,514.7	$2,206.1	$308.6

Default Supply Sales (KwH)	2004	2003	Change
Residential	16,768	16,048	720
Commercial	19,338	18,134	1,204
Industrial	2,294	2,882	(588)
Other	96	94	2
Total Default Supply Sales	38,496	37,158	1,338

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Default Supply Customers (000s)	2004	2003	Change
Residential	1,510	1,460	50
Commercial	180	175	5
Industrial	2	2	-
Other	1	1	-
Total Default Supply Customers	1,693	1,638	55

     Default Supply Revenue increased $308.6 million primarily due to the following: (i) $109.2 million as the result of higher retail energy rates, the result of effective rate increases in Delaware beginning October 2003 and in Maryland beginning in June and July 2004, (ii) $92.3 million primarily due to a reduction in customer migration in DC, (iii) $83.1 million increase in wholesale energy prices as the result of higher market prices in 2004, and (iv) $24.4 million increase in average customer usage.

     Other Electric Revenue decreased $31.9 million primarily due to a $43.0 million decrease that resulted from the expiration on December 31, 2003 of a contract to supply electricity to Delaware Municipal Electric Corporation (DMEC). This decrease was partially offset by a $14.0 million increase in customer requested work (related costs in Operations and Maintenance).

     Gas Operating Revenue

Regulated Gas Revenue	2004	2003	Change
Residential	$100.0	$ 88.8	$11.2
Commercial	56.4	47.7	8.7
Industrial	8.1	9.2	(1.1)
Transportation and Other	4.6	4.5	.1
Total Regulated Gas Revenue	$169.1	$150.2	$18.9

Regulated Gas Sales (Mcf)	2004	2003	Change
Residential	8.7	9.0	(.3)
Commercial	5.5	5.5	-
Industrial	1.2	1.6	(.4)
Transportation and Other	6.2	6.8	(.6)
Total Regulated Gas Sales	21.6	22.9	(1.3)

Regulated Gas Customers (000s)	2004	2003	Change
Residential	108.9	107.6	1.3
Commercial	9.1	9.1	-
Industrial	-	-	-
Transportation and Other	.1	.1	-
Total Regulated Gas Customers	118.1	116.8	1.3

     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.

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· Commercial activity in the region includes banking and other professional services, casinos, 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 $18.9 million principally due to the following: (i) $21.0 million increase in the Gas Cost Rate due to higher natural gas commodity costs; this was effective November 1, 2003, (ii) $8.2 million increase in Gas Base Rates due to higher operating expenses and cost of capital; this was effective December 9, 2003, and (iii) $2.0 million true up adjustment to unbilled revenues in 2003. These increases were partially offset by (iv) $9.4 million decrease due to 2003 being significantly colder than normal and (v) $2.9 million reduction related to lower industrial sales. Heating degree days decreased 7.1% for the year ended December 31, 2004 as compared to the same period in 2003.

     Other Gas Revenue increased $17.8 million largely related to an increase in off-system sales revenues of $17.3 million. The gas sold off-system was made available by warmer winter weather and reduced customer demand.

     Competitive Energy Business

     The following table categorizes the Competitive Energy business' operating revenue into major profit centers.

	2004	2003	Change
Merchant Generation	$  684.5	$  540.2	$ 144.3
POLR Load Service	695.3	972.2	(276.9)
Power, Oil & Gas Marketing Services and Other	1,028.5	1,346.6	(318.1)
Total Conectiv Energy Operating Revenue	$2,408.3	$2,859.0	$(450.7)
Pepco Energy Services	$1,168.6	$1,126.2	$  42.4

     Merchant Generation experienced an increase of $144.3 million, primarily due to $166.6 million from increased opportunities to take advantage of unit operating flexibility and increased power prices (approximately 11% higher). This increase was partially offset by $22.3 million from the implementation of EITF 03-11 on January 1, 2004. EITF 03-11 resulted in operating revenues and operating expenses related to certain energy contracts being reported on a net basis.

     POLR Load Service experienced a decrease of $276.9 million primarily due to a $152.9 million decrease in revenue from PJM due primarily to a change in power scheduling procedures by Conectiv to schedule power directly to DPL and a decrease of $187.9 million that related to the implementation of EITF 03-11 on January 1, 2004. This decrease was partially offset by increased hedging activity, including the recognition of an adjustment related to fuel supply contracts of $5.6 million.

     Power, Oil and Gas Marketing Services and Other decreased by $318.1 million primarily due to the expiration in 2003 of some large New Jersey Basic Generation Service contracts.

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     The increase in Pepco Energy Services' operating revenue of $42.4 million resulted from higher volumes of electricity sold to customers in 2004 at more favorable prices than in 2003, partially offset by a decrease in natural gas revenues.

Operating Expenses

     Fuel and Purchased Energy and Other Services Cost of Sales

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

	2004	2003	Change
Power Delivery	$2,523.8	$2,294.7	$229.1
Conectiv Energy	2,130.2	2,695.6	(565.4)
Pepco Energy Services	1,064.4	1,033.1	31.3
Other Non-Regulated	-	-	-
Corporate and Other	(821.8)	(820.8)	(1.0)
Total	$4,896.6	$5,202.6	$(306.0)

    Power Delivery's Fuel and Purchased Energy costs increased by $229.1 million primarily due to the following: (i) a $212.9 million increase related to higher average energy costs, the result of new Default Supply rates for Maryland beginning in June and July 2004 and for New Jersey beginning in June 2004 and less customer migration primarily in DC, (ii) $45.1 million higher costs due to the increased cost of electricity supply under the TPA Settlement with Mirant, effective October 2003, and (iii) a $30.2 million increase for gas commodity purchases, partially offset by (i) $43.0 million related to the DMEC 2003 contract expiration, and (ii) $14.5 million reserve recorded in September 2003 to reflect a potential exposure related to a pre-petition receivable from Mirant Corp. for which Pepco filed a creditor's claim in the bankruptcy proceedings.

     The following table categorizes the Competitive Energy business' fuel and purchased energy and other services cost of sales into major profit centers.

	2004	2003	Change
Merchant Generation	$  443.6	$  356.0	$  87.6
POLR Load Service	682.6	975.3	(292.7)
Power, Oil & Gas Marketing Services and Other	1,004.0	1,364.3	(360.3)
Total Conectiv Energy Fuel and Purchased   Energy and Other Services Cost of Sales	$2,130.2	$2,695.6	$(565.4)
Pepco Energy Services	$1,064.4	$1,033.1	$  31.3

     The decrease of $565.4 million in Conectiv Energy's fuel, purchased energy and other services cost of sales is broken down as follows:

     Merchant Generation increased by $87.6 million mainly due to an increase of $109.9 million primarily due to higher fuel costs (approximately 7% higher). This increase was partially offset by a $22.3 million decrease from the implementation of EITF 03-11 on January 1, 2004.

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     POLR Load Service decreased by $292.7 million partially due to a change in power scheduling procedures by Conectiv at PJM resulting in a $154.3 million decrease and a decrease of approximately $187.9 million that related to the implementation of EITF 03-11 on January 1, 2004. This decrease was partially offset by an increase in hedging activity.

     Power, Oil and Gas Marketing Services and Other decreased by $360.3 million due to the expiration of some large New Jersey Basic Generation Service contracts in 2003.

     The increase in Pepco Energy Services' fuel and purchased energy and other services cost of sales of $31.3 million resulted from higher volumes of electricity purchased in 2004 to serve customers, partially offset by a decrease in volumes of natural gas purchased in 2004 to serve customers.

     Other Operation and Maintenance

     PHI's other operation and maintenance increased by $32.1 million to $799.9 million in 2004 from $767.8 million in 2003 primarily due to (i) $12.1 million of customer requested work (offset in Other Electric Revenue), (ii) $10.6 million higher electric system operation and maintenance costs, (iii) $9.4 million in Sarbanes-Oxley external compliance costs, (iv) $12.8 million severance costs, partially offset by $10.6 million incremental storm costs primarily related to one time charges as a result of Hurricane Isabel in September 2003.

     Depreciation and Amortization

     PHI's depreciation and amortization expenses increased by $18.4 million to $440.5 million in 2004 from $422.1 million in 2003 primarily due to a $17.0 million increase attributable to the Power Delivery business resulting from (i) a $12.8 million increase for amortization of New Jersey bondable transition property as a result of additional transitional bonds issued in December 2003; (ii) $3.8 million for the amortization of the New Jersey deferred service costs balance which began in August 2003; and (iii) a $2.4 increase for amortization of a regulatory tax asset related to New Jersey stranded costs. Additionally, depreciation expense attributable to the Competitive Energy business increased by $5.9 million from 2003 due to a full year of depreciation expense during 2004 at Conectiv Energy's Bethlehem facility.

     Other Taxes

     Other taxes increased by $28.9 million to $302.8 million in 2004 from $273.9 million in 2003. This increase primarily resulted from a $30.1 million increase attributable to the Power Delivery business due to pass-throughs of $33.9 million higher county surcharge and $3.6 million higher gross receipts/delivery taxes (offset in Regulated T&D Electric Revenue), partially offset by $9.5 million lower property tax expense due to true-ups recorded in 2004.

     Deferred Electric Service Costs

     Deferred Electric Service Costs (DESC), which relates only to ACE, increased by $43.3 million to $36.3 million in 2004 from a $7.0 million operating expense credit in 2003. At December 31, 2004, DESC represents the net expense or over-recovery associated with New Jersey NUGs, MTC and other restructuring items. A key driver of the $43.3 million change was $27.5 million for the New Jersey deferral disallowance from 2003. ACE's rates for

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the recovery of these costs are reset annually and the rates will vary year to year. On ACE's balance sheet a regulatory asset includes an under-recovery of $99.4 million as of December 31, 2004. This amount is net of a $46.1 million write-off on previously disallowed items under appeal.

     Impairment Losses

     The impairment losses recorded by PHI in 2003 consist of an impairment charge of $53.3 million from the cancellation of a CT contract and an $11.0 million aircraft impairment.

     Gain on Sale of Assets

     During 2004 PHI recorded $30.0 million in pre-tax gains on the sale of assets compared to a $68.8 million pre-tax gain in 2003. The 2004 pre-tax gains primarily consist of (i) a $14.7 million pre-tax gain from the condemnation settlement with the City of Vineland relating to the ACE transfer of distribution assets and customer accounts, (ii) an $8.3 million pre-tax gain on the sale of aircraft by PCI, and (iii) a $6.6 million pre-tax gain on the sale of land. The $68.8 million pre-tax gain in 2003 represents the gain on the sale of PHI's office building which was owned by PCI.

Other Income (Expenses)

     PHI's other expense (which is net of other income) decreased $88.0 million to $341.0 million in 2004, from $429.0 million in 2003. The decrease was primarily due to a pre-tax impairment charge of $102.6 million related to PHI's investment in Starpower that was recorded during 2003, compared to an additional pre-tax impairment charge of $11.2 million that was recorded during the second quarter of 2004.

Preferred Stock Dividend Requirements of Subsidiaries

     Preferred Stock Dividend Requirements decreased by $11.1 million to $2.8 million in 2004 from $13.9 million in 2003. Of this decrease, $6.9 million was attributable to SFAS No. 150, which requires that dividends on Mandatorily Redeemable Serial Preferred Stock declared subsequent to July 1, 2003 be recorded as interest expense. An additional $4.6 million of the decrease resulted from lower dividends in 2004 due to the redemption of the Trust Originated Preferred Securities in 2003.

Income Tax Expense

     Pepco Holdings' effective tax rate for 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), the flow-through of certain book tax depreciation differences and the settlement with the IRS on certain non-lease financial assets (which is the primary reason for the higher effective tax rate as compared to 2003), partially offset by the flow-through of Deferred Investment Tax Credits and tax benefits related to certain leveraged leases and the benefit associated with the retroactive adjustment for the issuance of final consolidated tax return regulations by a taxing authority.

     Pepco Holdings' effective tax rate for 2003 was 37% 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 tax benefits related to certain leveraged leases.

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     The results of operations discussion below is for the year ended December 31, 2003 compared to the year ended December 31, 2002.

Revised Segment Presentation

     In accordance with the provisions of SFAS No. 131, results for the years ended December 31, 2003 and 2002 have been revised to conform to the 2004 segment presentation. This was required by Statement of Financial Accounting Standards (SFAS) No. 131 "Disclosures about Segments of an Enterprise and Related Information," because Pepco Holdings' management identified its operating segments at January 1, 2004 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. Prior to January 1, 2004, Pepco Holdings' Power Delivery business consisted of two operating segments, Pepco and Conectiv Power Delivery. However, with the continued integration of the Power Delivery businesses, effective January 1, 2004 these two businesses represented a single operating segment. Additionally, effective January 1, 2004, PHI transferred several operating businesses from one operating segment to another in order to better align their operations going forward.

Lack of Comparability of 2003 and 2002 Operating Results

     The accompanying results of operations for the year ended December 31, 2003 include Pepco Holdings' and its subsidiaries' results for the full year. Because of merger accounting that was used to record Pepco's acquisition of Conectiv, the results of operations for 2002 include the results of Pepco and its pre-merger subsidiaries (PCI and Pepco Energy Services) for the entire year consolidated with the results of Conectiv and its subsidiaries starting on August 1, 2002, the date the merger was completed. Accordingly, the results of operations for 2003 and 2002 are not comparable.

Operating Revenue

     PHI's operating revenue increased by $2,946.8 million to $7,271.3 million in 2003, from $4,324.5 million in 2002. This increase was primarily due to an increase in operating revenue of $1,497.2 million at Power Delivery, an increase of $1,645.7 million at Conectiv Energy, and an increase of $260.5 million at Pepco Energy Services. Intercompany revenues that are eliminated in consolidation are included as part of business segment operating revenues.

     The $1,497.2 million increase in Power Delivery's operating revenue for 2003 primarily resulted from the fact that PHI recognized $2,489.7 million in revenue from Conectiv Power Delivery in 2003 (full year) vs. $997.4 million during 2002 (post August 1, 2002 merger date operations), an increase of $1,492.3 million. Additionally, Pepco's operating revenues increased by $14.1 million in 2003. The $14.1 million increase in Pepco's operating revenue in 2003 resulted from the following:

     Delivery revenue increased by $18.5 million for the year ended December 31, 2003. This increase results from a $19.2 million increase from a fuel tax pass through, partially offset by $.7 million decrease in Delivery revenue (revenue Pepco receives for delivering energy to its customers). The $.7 million decrease results from a .6% decrease in delivered kilowatt-hour sales.

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     Standard offer service (SOS) revenue (revenue Pepco receives for the procurement of energy by Pepco for its SOS customers) increased by $4.2 million for the year ended December 31, 2003 due to colder winter weather as heating degree days increased by 12.2%, offset by milder summer weather as cooling degree days decreased by 30.2%.

     Pepco's retail access to a competitive market for generation services was made available to all Maryland customers on July 1, 2000 and to D.C. customers on January 1, 2001. As of December 31, 2003, 14% of Pepco's Maryland customers and 11% of its D.C. customers had chosen alternate suppliers. These customers accounted for 912 megawatts of load in Maryland (of Pepco's total load of 3,439) and 970 megawatts of load in D.C. (of Pepco's total load of 2,269). As of December 31, 2002, 16% of Pepco's Maryland customers and 13% of its D.C. customers had chosen alternate suppliers. These customers accounted for 1,175 megawatts of load in Maryland (of Pepco's total load of 3,369) and 1,140 megawatts of load in D.C. (of Pepco's total load of 2,326).

     Pepco's other revenue decreased $8.6 million primarily due to lower capacity (megawatts) available to sell, lower capacity market rates and restructuring in the PJM market.

     The $1,645.7 million increase in Conectiv Energy's operating revenue during 2003 resulted from the fact that PHI recognized $2,859.0 million in revenue in 2003 (full year) vs. $1,213.3 million during 2002 (post August 1, 2002 merger date operations).

     The increase in Pepco Energy Services' operating revenue during 2003 of $260.5 million was primarily due to growth in its commodity business from sales of electricity and natural gas due to higher volumes which resulted from more commercial and industrial customers being served and higher prices due to wholesale commodity market conditions. In 2003, wholesale and retail megawatt hour sales increased by approximately 16% and wholesale and retail dekatherm sales increased by approximately 19%.

Operating Expenses

     Fuel and Purchased Energy and Other Services Cost of Sales

     PHI's fuel and purchased energy and other services cost of sales increased by $2,400.8 million to $5,202.6 million in 2003 from $2,801.8 million in 2002. This increase was primarily due to an increase in Power Delivery of $1,005.8 million, an increase in Conectiv Energy of $1,598.4 million, and an increase in Pepco Energy Services of $255.1 million. Intercompany fuel purchases that are eliminated in consolidation are included in business segment fuel purchases.

     The $1,005.8 million increase in Power Delivery's fuel and purchased energy and other services cost of sales for 2003 primarily resulted from the fact that PHI recognized $1,610.5 million in fuel and purchased energy and other services cost of sales from Conectiv Power Delivery in 2003 (full year) vs. $641.2 million during 2002 (post August 1, 2002 merger date operations), an increase of $969.3 million. Additionally, Pepco's fuel and purchased energy increased by $29.8 million in 2003. The $29.8 million increase in Pepco's fuel and purchased energy in 2003 resulted from the recording of a $14.5 million reserve to reflect a potential exposure related to a pre-petition receivable from Mirant Corp., for which Pepco filed a creditor's claim in bankruptcy proceedings and from $15.3 million from higher SOS costs.

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     The $1,598.4 million increase in Conectiv Energy's fuel and purchased energy and other services cost of sales for 2003 primarily resulted from the fact that PHI recognized $2,695.6 million in fuel and purchased energy and other services cost of sales from Conectiv Energy in 2003 (full year) vs. $1,097.2 million during 2002 (post August 1, 2002 merger date operations), an increase of $1,598.4 million.

     The increase in Pepco Energy Services' fuel and purchased energy and other services cost of sales during 2003 of $255.1 million primarily resulted from growth in its retail commodity business for sales of electricity and natural gas due to higher volumes which resulted from more commercial and industrial customers being served and higher prices due to wholesale commodity market conditions.

     Other Operation and Maintenance

     PHI's other operation and maintenance increased by $243.9 million to $767.8 million in 2003 from $523.9 million in 2002. This increase was primarily due to an increase in Power Delivery of $212.7 million and an increase in Conectiv Energy of $55.4 million. The $212.7 million increase in Power Delivery's other operation and maintenance for 2003 primarily resulted from the fact that PHI recognized $394.9 million in other operation and maintenance from Conectiv Power Delivery in 2003 (full year) vs. $146.3 million during 2002 (post August 1, 2002 merger date operations), an increase of $248.6 million.

     Depreciation and Amortization

     PHI's depreciation and amortization increased by $182.3 million to $422.1 million in 2003 from $239.8 million in 2002. This increase was primarily due to an increase in Power Delivery of $147.0 million and an increase in Conectiv Energy of $26.8 million. The $147.0 million increase in Power Delivery's depreciation and amortization for 2003 primarily resulted from the fact that PHI recognized $186.2 million in depreciation and amortization from Conectiv Power Delivery in 2003 (full year) vs. $62.8 million during 2002 (post August 1, 2002 merger date operations), an increase of $123.4 million. Additionally, Pepco's depreciation and amortization increased by $23.2 million in 2003 due to software amortization.

     Other Taxes

     PHI's other taxes increased by $48.3 million to $273.9 million in 2003 from $225.6 million in 2002. This increase was primarily due to an increase in Power Delivery of $44.4 million. The $44.4 million increase in Power Delivery's other taxes for 2003 primarily resulted from the fact that PHI recognized $59.7 million in other taxes from Conectiv Power Delivery in 2003 (full year) vs. $24.8 million during 2002 (post August 1, 2002 merger date operations), an increase of $34.9 million. Additionally, Pepco's other taxes increased by $9.1 million in 2003 due to higher fuel taxes.

     Deferred Electric Service Costs

     PHI's deferred electric service costs increased by $5.2 million in 2003 due to the net under-recovery associated with New Jersey NUGs, MTC and other restructuring items.

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     Impairment Losses

     The $64.3 million in impairment losses in 2003 consists of charges of $53.3 million for Conectiv Energy CT contract cancellation and write downs and $11.0 million related to a PCI aircraft write-down.

     Gain on Sale of Assets

     The $68.8 million gain on sale of assets is recorded net against operating expenses and represents the gain on the sale of PHI's office building in 2003 which was owned by PCI.

Other Income (Expenses)

     PHI's other expenses increased by $238.6 million to $429.0 million in 2003 from $190.4 million in 2002. This increase was primarily due to an increase in other expenses of $57.6 million recognized at Power Delivery, an increase of $99.7 million in Other Non Regulated, and an increase of $65.0 million in Corporate and Other.

     The $57.6 million increase in Power Delivery's other expenses for 2003 primarily resulted from the fact that PHI recognized $82.4 million in expenses from Conectiv Power Delivery in 2003 (full year) vs. $38.1 million in 2002 (post August 1, 2002 merger date operations), an increase of $44.3 million.

     The $99.7 million increase in Other Non Regulated operating expense for the year ended 2003 primarily includes an impairment charge of $102.6 million ($66.7 million after-tax) related to PHI's investment in Starpower. Because of the distressed telecommunications market and the changed expectations of Starpower's future performance, PHI determined that its investment in Starpower was impaired at December 31, 2003.

     "Corporate and other" in 2003 primarily represents unallocated PHI capital costs, incurred as a result of long-term acquisition financing entered into in late 2002.

Income Tax Expense

     Pepco Holdings effective tax rates in 2003 and 2002 were 37% compared to the federal statutory rate of 35%. The major reasons for this difference are 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 the tax benefits related to certain leveraged leases.

Extraordinary Item

     In July 2003, the New Jersey Board of Public Utilities (NJBPU) approved the determination of stranded costs related to ACE's January 31, 2003, petition relating to its B.L. England generating facility. The NJBPU approved recovery of $149.5 million. As a result of the order, ACE reversed $10.0 million of accruals for the possible disallowances related to these stranded costs. The credit to income of $5.9 million is classified as an extraordinary gain in Pepco Holdings' financial statements, since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.

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CAPITAL RESOURCES AND LIQUIDITY

     This section discusses Pepco Holdings' capital structure, cash flow activity, capital spending plans and other uses and sources of capital for 2004 and 2003.

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 transition bonds issued by Atlantic City Electric Transition Funding LLC (ACE Funding) and PES' project funding secured by customer accounts receivable) is shown below as of December 31, 2004 and 2003. The debt issued by ACE Funding and Pepco Energy Services project funding, which are both effectively securitized, are excluded because the major credit rating agencies treat effectively securitized debt separately and not as general obligations of the Company, when computing credit quality measures. (Dollars in Millions).

	2004		2003
Common Shareholders' Equity	$3,366.3	39.2%	$3,003.3	34.6%
Preferred Stock (a)	54.9	.6	108.2	1.3
Debentures Issued to Financing Trust (b)	-	-	98.0	1.1
Long-Term Debt (c)	5,003.3	58.3	5,101.3	58.8
Short-Term Debt (d)	161.3	1.9	360.0	4.2
Total	$8,585.8	100.0%	$8,670.8	100.0%

(a)	Represents Mandatorily Redeemable Serial Preferred Stock of a Subsidiary, Serial Preferred Stock, and Redeemable Serial Preferred Stock issued by subsidiaries of PHI.
(b)	Represents debentures issued to financing trusts and current portion of debentures issued to financing trusts.
(c)	Includes first mortgage bonds, medium term notes, other long-term debt (other than debt issued by ACE Funding and Pepco Energy Services project funding), current maturities of long-term debt (other than debt issued by ACE Funding and Pepco Energy Services project funding), and Variable Rate Demand Bonds. Excludes capital lease obligations, transition bonds issued by ACE Funding, and Pepco Energy Services' project funding secured by customer accounts receivable.
(d)	Excludes current maturities of long-term debt, capital lease obligations due within one year, and Variable Rate Demand Bonds.

     In 2003, PHI established a goal of reducing its total debt and preferred stock outstanding by $1 billion by the end of 2007 to improve PHI's interest coverage ratios and achieve a ratio of consolidated equity to total capital (excluding Transition Bonds issued by ACE Funding and Pepco Energy Services' project funding) in the mid-40% range. The debt reduction goal is expected to be met through a combination of internally generated cash, equity issuances through its Shareholder Dividend Reinvestment Plan (DRP), and asset dispositions.

· In 2004, PHI reduced its debt and preferred stock outstanding by approximately $480 million through a combination of cash flow from operating activities, less investing activities and dividends (approximately $134 million), proceeds from the issuance of PHI common stock, including the DRP, net of issuance costs (approximately $308 million), and reduction in cash and cash equivalents, net of other financing costs (approximately $38 million).

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· In 2003, PHI reduced its debt and preferred stock outstanding by approximately $250 million through a combination of cash flow from operating activities, less investing activities and dividends (approximately $231 million), proceeds from the issuance of common stock, primarily through the DRP, net of issuance costs (approximately $33 million), and less the increase in cash and cash equivalents net of other financing costs (approximately $14 million).

     Because the $278 million public offering of PHI common stock in 2004 was not contemplated in the original $1 billion of debt reduction plan, PHI has raised its debt reduction goal to $1.3 billion by 2007. (See Risk Factors for a description of factors that could cause PHI to not meet this goal.)

     Set forth below is a summary of long-term financing activity during 2004 for Pepco Holdings and its subsidiaries.

     Pepco Holdings issued 1,471,936 shares of common stock under its Shareholder Dividend Reinvestment Plan and various benefit plans. The proceeds from the issuances were added to PHI's general funds.

     Pepco Holdings sold 14,950,000 shares of common stock at $19.25 per share. The proceeds, in combination with short-term debt, were used to pre-pay in its entirety a term loan in the amount of $335 million of Conectiv Bethlehem, LLC.

     Pepco issued $275 million of secured senior notes with maturities of 10 and 30 years. Proceeds of $272.8 million were used to redeem higher interest rate securities of $210 million and to repay short-term debt of $56.6 million. Pepco borrowed $100 million under a bank loan due in 2006. Proceeds were used to redeem mandatorily redeemable preferred stock of $42.5 million and to repay short-term debt.

     DPL issued $100 million of unsecured notes that mature in 2014. Proceeds of $98.9 million were used to redeem trust preferred securities of $70 million and to repay short-term debt.

     ACE issued $54.7 million of insured auction rate tax-exempt securities and $120 million of secured senior notes which mature in 2029 and 2034 respectively. Proceeds of $173.2 million were used to redeem higher interest rate securities.

Working Capital

     At December 31, 2004, Pepco Holdings' current assets on a consolidated basis totaled $1.7 billion and its current liabilities totaled $1.9 billion. At December 31, 2003, PHI's current assets totaled $1.7 billion and its current liabilities totaled $2.2 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 energy supplies for their customers before the supplies are delivered to, 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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     A detail of PHI's short-term debt balance is as follows:

	As of December 31, 2004 ($ in Millions)
Type	PHI Parent	Pepco	DPL	ACE	ACE Funding	Conectiv Energy	PES	PCI	Conectiv	PHI Consolidated
Variable Rate   Demand Bonds	$    -	$    -	$104.8	$22.6	$   -	$  -	$31.0	$   -	$    -	$158.4
Current Portion   of Long-Term   Debt	-	100.0	2.7	40.0	28.1	-	.1	60.0	280.0	510.9
Project Funding   Secured by   Accounts   Receivable	-	-	-	-	-	-	5.4	-	-	5.4
Floating Rate   Note	50.0	-	-	-	-	-	-	-	-	50.0
Commercial Paper	78.6	-	-	32.7	-	-	-	-	-	111.3
Total	$128.6	$100.0	$107.5	$95.3	$28.1	$  -	$36.5	$60.0	$280.0	$836.0

	As of December 31, 2003 ($ in Millions)
Type	PHI Parent	Pepco	DPL	ACE	ACE Funding	Conectiv Energy	PES	PCI	Conectiv	PHI Consolidated
Variable Rate   Demand Bonds	$    -	$   -	$104.8	$22.6	$   -	$  -	$ 31.0	$   -	$    -	$158.4
Current Portion   of Long-Term   Debt	200.0	-	7.0	11.0	25.9	-	-	86.0	50.0	379.9
Project Funding   Secured by   Accounts   Receivable	-	-	-	-	-	-	5.0	-	-	5.0
Construction   Loan	-	-	-	-	-	310.0	-	-	-	310.0
Floating Rate   Note	-	50.0	-	-	-	-	-	-	-	50.0
Commercial Paper	-	-	-	-	-	-	-	-	-	-
Total	$200.0	$50.0	$111.8	$33.6	$25.9	$310.0	$36.0	$86.0	$50.0	$903.3

Cash Flow Activity

     PHI's cash flows for 2004, 2003, and 2002 are summarized below.

	Cash Source / (Use)
	2004	2003	2002
	(Dollars in Millions)
Operating Activities	$734.6	$661.4	$   793.1
Investing Activities	(422.1)	(254.8)	(1,964.9)
Financing Activities	(373.5)	(367.9)	718.1
Net change in cash and cash equivalents	$(61.0)	$ 38.7	$  (453.7)

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     Operating Activities

     Cash flows from operating activities are summarized below for 2004, 2003, and 2002.

	Cash Source / (Use)
	2004	2003	2002
	(Dollars in Millions)
Net Income	$258.7	$113.5	$210.5
Non-cash adjustments to net income	495.2	685.5	472.4
Changes in working capital	(19.3)	(137.6)	110.2
Net cash provided by operating activities	$734.6	$661.4	$793.1

     Cash from operations is the primary source used to meet operating requirements and capital expenditures. Net cash flows provided by operating activities increased by $73.2 million to $734.6 million for 2004 from $661.4 million for 2003. The $73.2 million increase was largely the result of improved operating results at PHI's regulated utilities. Regulated T&D Electric experienced a 2% KwH growth rate in 2004, and regulated T&D Revenue increased by $45.7 million primarily due to customer growth and increased average usage, higher average effective rates, and favorable warmer weather. PHI Power Delivery produced over 85% of consolidated cash from operations in 2004 and 2003.

     In 2003, cash flows from operating activities decreased by $131.7 million to $661.4 million from $793.1 million for 2002. The $131.7 million decrease was due to higher interest payments in 2003 and a federal income tax refund in 2002.

     Investing Activities

     The most significant items included in cash flows from investing activities during 2004, 2003, and 2002 are summarized below.

	Cash Source / (Use)
	2004	2003	2002
	(Dollars in Millions)
Acquisition of Conectiv	$     -	$     -	$(1,075.6)
Capital expenditures	(517.4)	(598.2)	(503.8)
Cash proceeds from sale of:
Starpower investment	29.0	-	-
Marketable securities, net	19.4	156.6	(7.0)
Office building and other properties	46.4	147.7	4.0
Purchase of leveraged leases	-	-	(319.6)
All other investing cash flows, net	.5	39.1	(62.9)
Net cash used by investing activities	$(422.1)	$(254.8)	$(1,964.9)

     Capital expenditures decreased $80.8 million for 2004 to $517.4 million from $598.2 million for 2003. This decrease was primarily due to lower construction expenditures for Conectiv Energy, offset by an increase in Power Delivery capital requirements to upgrade electric transmission and distribution systems.

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     Capital expenditures increased $94.4 million for 2003 to $598.2 million from $503.8 million for 2002. This increase was primarily due to 2002 including five months of Conectiv companies as a result of the August 1, 2002 acquisition of Conectiv by Pepco.

     In 2002, net cash used by investing activities included the cash outflow of $1,075.6 million related to Pepco's acquisition of Conectiv. Excluding the impact of the Conectiv acquisition by Pepco and the investments in hydro-electric facility leveraged leases, investing activities used a net cash flow of $569.7 million compared to $254.8 million in 2003 primarily due to PCI's liquidation of its marketable securities portfolio and the sale of its final real estate investment. PHI announced in the second quarter of 2003 the discontinuation of further investment activity by PCI.

      In December 2004, Pepcom sold its 50% interest in Starpower for $29 million in cash. Additionally in 2004 PHI received proceeds from the sale of aircraft and land.

     In September 2003 Potomac Capital Investment (PCI) sold an office building known as Edison Place (which serves as headquarters for PHI and Pepco).

     Financing Activities

	Cash Source / (Use)
	2004	2003	2002
	(Dollars in Millions)
Common Stock Dividends	$  (176.0)	$(170.7)	$  (130.6)
Common Stock Issuances	318.0	32.8	118.1
Preferred Stock Redemptions	(53.3)	(197.5)	(9.9)
Long term Debt Issuances	650.4	1,136.9	1,981.7
Long term Debt Redemptions	(1,214.7)	(692.2)	(415.2)
Short term Debt, net	136.3	(452.7)	(684.8)
Other	(34.2)	(24.5)	(141.2)
Net cash (Used By) Provided By   financing activities	$  (373.5)	$(367.9)	$  718.1

     Common stock dividend payments were $176.0 million in 2004, $170.7 million in 2003, and $130.6 million in 2002. The increase in common dividends paid in 2004 was due to the issuance of 14,950,000 shares of common stock in September 2004 and issuances of 1,471,936 shares of common stock by the Company's Dividend Reinvestment Plan. The increase in 2003 was due to the August 1, 2002 acquisition of Conectiv by Pepco.

     In 2004, Pepco redeemed its remaining 900,000 shares of $3.40 series mandatorily redeemable preferred stock for $45 million, and 165,902 shares of $2.28 series preferred stock for $7.7 million. In 2003, redemptions of mandatorily redeemable trust preferred securities included $125 million for Pepco, $70 million for DPL, and $95 million for ACE.

     In 2004, Pepco issued $275 million of secured senior notes with maturities of 10 and 30 years; proceeds were used to redeem higher interest rate securities and to repay short-term debt. Pepco borrowed $100 million under a bank loan due in 2006, and proceeds were used to redeem mandatorily redeemable preferred stock and repay short-term debt.  DPL issued $100 million of unsecured notes that mature in 2014, and proceeds were used to redeem trust preferred securities and repay short-term debt. ACE issued $54.7 million of insured auction rate tax-exempt securities and $120 million

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of secured senior notes which mature in 2029 and 2034 respectively; proceeds were used to redeem higher interest rate securities.

     In 2003, Pepco Holdings issued $700 million of unsecured long-term debt with maturities ranging from 1 year to 7 years; proceeds were used to repay short-term debt. Pepco issued $200 million of secured senior notes, and proceeds were used to refinance $125 million trust preferred securities and repay short-term debt. DPL issued $33.2 million of tax-exempt bonds having maturities ranging from 5 to 35 years, and proceeds were used to refinance higher interest debt. ACE Funding issued $152 million of Transition Bonds with maturities ranging from 8 to 17 years, and proceeds will be used to recover the stranded costs associated with an ACE generation asset and transaction costs.

     In December 2002, Pepco Holdings sold 5,750,000 shares of common stock at $19.13 per share. In September 2004, Pepco Holdings sold 14,950,000 shares of common stock at $19.25 per share. 3,808,135 shares of common stock have also been issued during the three-year period pursuant to the Company's Dividend Reinvestment Program.

     In 2002, Pepco Holdings issued $1.35 billion of unsecured notes: $350 million of 5.50% notes due in 2007, $750 million of 6.45% notes due in 2012, and $250 million of 7.45% notes due 2032. The proceeds from the sale of these notes were used to repay approximately $1.1 billion of indebtedness outstanding in connection with the Merger, and to repay approximately $240 million of outstanding commercial paper, including $106.1 million of commercial paper issued to fund the settlement of treasury lock transactions. Also, Pepco Holdings issued an additional $150 million of 5.5% notes due 2007, the proceeds of which were used to repay outstanding commercial paper. In addition, pursuant to a Stranded Cost Rate Order issued by the NJBPU, ACE Funding issued $440 million Transition Bonds, the proceeds of which will be used to recover stranded costs.

Capital Requirements

     Construction Expenditures

     Pepco Holdings' construction expenditures for the year ended December 31, 2004 totaled $517.4 million of which $479.5 million was related to its power delivery businesses and the remainder related to Conectiv Energy and Pepco Energy Services. For the five-year period 2005 through 2009, total construction expenditures are projected to be approximately $2.1 billion, of which approximately $2.0 billion is related to the Power Delivery business. This amount includes estimated costs for environmental compliance by PHI's subsidiaries. See Item 1 -- "Business -- Environmental Matters." Pepco Holdings expects to fund these expenditures through internally generated cash from the power delivery businesses.

     Dividends

     Pepco Holdings' annual dividend rate on its common stock is determined by the Board of Directors on a quarterly basis and takes into consideration, among other factors, current and possible future developments that may affect PHI's income and cash flows. PHI's Board of Directors declared quarterly dividends of 25 cents per share of common stock payable on March 31, 2004, June 30, 2004, September 30, 2004 and December 31, 2004.

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     On January 25, 2005, Pepco Holdings declared a dividend on common stock of 25 cents per share payable March 31, 2005, to shareholders of record March 10, 2005.

     Under PUHCA, PHI is prohibited, without SEC approval, from paying dividends on its common stock from capital or unearned surplus. PHI generates no operating income of its own. Accordingly, its ability to pay dividends to its shareholders depends on dividends received from its subsidiaries. In addition to their future financial performance, the ability of PHI's direct and indirect subsidiaries to pay dividends is subject to limits imposed by: (i) state corporate and regulatory laws, which impose limitations on the funds that can be used to pay dividends and, in the case of regulatory laws, as applicable, may require the prior approval of the relevant utility regulatory commissions before dividends can be paid; (ii) PUHCA, which prohibits a subsidiary of a registered public utility holding company from paying a dividend out of capital or unearned surplus without the prior approval of the SEC; (iii) the prior rights of holders of existing and futu re preferred stock, mortgage bonds and other long-term debt issued by the subsidiaries, and any other restrictions imposed in connection with the incurrence of liabilities, and (iv) certain provisions of the charters of Pepco, DPL and ACE, which impose restrictions on payment of common stock dividends for the benefit of preferred stockholders.

     Pepco's articles of incorporation and DPL's certificate and articles of incorporation each contains provisions restricting the amount of dividends that can be paid on common stock when preferred stock is outstanding if the applicable company's capitalization ratio is less than 25%. For this purpose, the capitalization ratio is equal to (i) common stock capital plus surplus, divided by (ii) total capital (including long-term debt) plus surplus. In addition, DPL's certificate and articles of incorporation and ACE's certificate of incorporation each provides that if preferred stock is outstanding, no dividends may be paid on common stock if, after payment, the applicable company's common stock capital plus surplus would be less than the involuntary liquidation value of the outstanding preferred stock. Currently, none of these charter restrictions limits the ability of Pepco, DPL or ACE to pay dividends.

Pension Funding

     Pepco Holdings has a noncontributory retirement plan (the Retirement Plan) that covers substantially all employees of Pepco, Conectiv and certain employees of other Pepco Holdings' subsidiaries. Following the consummation of the acquisition of Conectiv by Pepco on August 1, 2002, the Pepco General Retirement Plan and the Conectiv Retirement Plan were merged into the Retirement Plan on December 31, 2002. The provisions and benefits of the merged Retirement Plan applicable to Pepco employees are identical to those in the original Pepco plan and the provisions and benefits applicable to Conectiv employees are identical to those in the original Conectiv plan.

     As of the 2004 valuation, the Retirement Plan satisfied the minimum funding requirements of the Employment Retirement Income Security Act of 1974 (ERISA) without requiring any additional funding. However, PHI's funding policy with regard to the Retirement 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 Retirement Plan in accordance with its funding policy.

     In 2004, the accumulated benefit obligation for the Retirement Plan increased over 2003, due to the accrual of an additional year of service for

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participants and a decrease in the discount rate used to value the accumulated benefit obligation. The change in the discount rate reflected the continued decline in interest rates in 2004. The Retirement Plan assets achieved returns in 2004 in excess of the levels assumed in the valuation. As a result of the combination of these factors, in December 2004 PHI contributed $10 million (all of which was funded by Pepco) to the Retirement Plan. The contribution was made to ensure that under reasonable assumptions, the funding level at year end would be in excess of 100% of the accrued benefit obligation. In 2003, PHI contributed a total of $50 million (of which $30 million was funded by Pepco and $20 million was funded by ACE) to the Retirement Plan. Assuming no changes to the current pension plan assumptions, PHI projects no funding will be required under ERISA in 2005; however, PHI may elect to make a discretionary tax-deductible contribution, if required to main tain its assets in excess of its ABO.

     Contractual Obligations And Commercial Commitments

     Summary information about Pepco Holdings' consolidated contractual obligations and commercial commitments at December 31, 2004, is as follows:

	Contractual Maturity
Obligation	Total	Less than 1 Year	1-3   Years	4-5   Years	After     5 Years
	(Dollars in Millions)
Short-term debt	$  161.3	$161.3	$      -	$    -	$      -
Variable rate demand bonds	158.4	158.4	-	-	-
Long-term debt	5,466.9	516.2	1,403.8	400.3	3,146.6
Interest payments on debt	2,898.7	294.8	511.0	378.4	1,714.5
Capital leases	230.1	15.9	31.3	30.6	152.3
Operating leases	578.5	38.2	76.4	78.0	385.9
Fuel and purchase power   contracts (a)	7,220.8	1,343.9	1,761.1	725.4	3,390.4
Payments under interest rate   swap agreements	25.4	6.0	13.1	6.3	-
Total	$16,740.1	$2,534.7	$3,796.7	$1,619.0	$8,789.7

(a) Excludes the PPA Related Obligations that are part of the back-to-back agreement that was entered into with Mirant. Refer to the "Relationship with Mirant" section herein for additional information.

     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 December 31, 2004, 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:

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	Guarantor
	PHI	Conectiv	PCI	Total
Energy marketing obligations of   Conectiv Energy (1)	$141.9	$ 1.6	$  -	$143.5
Energy procurement obligations   ofPepco Energy Services (1)	7.8	-	-	7.8
Standby letters of credit of   Pepco Holdings (2)	4.2	-	-	4.2
Guaranteed lease residual values (3)	0.6	6.2	-	6.8
Loan agreement (4)	13.1	-	-	13.1
Construction performance guarantees (5)	-	1.7	-	1.7
Other (6)	14.9	3.9	3.0	21.8
Total	$182.5	$13.4	$3.0	$198.9

1.	Pepco Holdings and Conectiv have 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 for ACE.
2.	Pepco Holdings has issued standby letters of credit of $4.2 million on behalf of subsidiary 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 $4.2 million, Pepco Holdings does not expect to fund the full amount.
3.	Subsidiaries of Pepco Holdings and Conectiv have guaranteed residual values in excess of fair value related to certain equipment and fleet vehicles held through lease agreements. As of December 31, 2004, obligations under the guarantees were approximately $6.8 million. Assets leased under agreements subject to residual value guarantees are typically for periods ranging from 2 years to 10 years. Historically, payments under the guarantee 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 requiring payment under the guarantee is remote.
4.	Pepco Holdings has issued a guarantee on behalf of a subsidiary's 50% unconsolidated investment in a limited liability company for repayment of borrowings under a loan agreement of approximately $13.1 million.
5.	Conectiv has performance obligations of $1.7 million relating to obligations to third party suppliers of equipment.
6.	Other guarantees comprise:
	·	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.
	·	Conectiv has guaranteed a subsidiary building lease of $3.9 million. PHI 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 December 31, 2004, the guarantees cover the remaining $3.0 million in rental obligations.

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     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 the agreements. Typically, claims may be made by third parties under these indemnification agreements over various periods of time depending on the nature of the claim. The maximum potential exposure under these indemnification agreements can range from a specified dollar amount to an unlimited amount depending on the nature of the claim and the particular transaction. The total maximum potential amount of future payments under these indemnification agreements is not estimable due to several factors, including uncertainty as to whether or when claims may be made under these indemnities.

     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 Year Ended December 31, 2004 (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, 2003	$ 11.0	$60.6	$ 71.6
Total change in unrealized fair value excluding     reclassification to realized at settlement of contracts	(0.4)	32.4	32.0
Reclassification to realized at settlement of contracts	(9.7)	(45.5)	(55.2)
Effective portion of changes in fair value - recorded     in OCI	-	(15.8)	(15.8)
Ineffective portion of changes in fair value -     recorded in earnings	-	(6.0)	(6.0)
Changes in valuation techniques and assumptions	-	-	-
Purchase/sale of existing contracts or portfolios     subject to MTM	-	-	-
Total MTM Energy Contract Net Assets at December 31, 2004 (a)	$ 0.9 (3)	$25.7	$ 26.6
(a) Detail of MTM Energy Contract Net Assets at December 31, 2004 (above)			Total
Current Assets (other current assets)			$ 88.7
Noncurrent Assets (other assets)			15.1
Total MTM Energy Assets			103.8
Current Liabilities (other current liabilities)			(54.6)
Noncurrent Liabilities (other liabilities)			(22.6)
Total MTM Energy Contract Liabilities			(77.2)
Total MTM Energy Contract Net Assets			$ 26.6

Notes:
(1)	Includes all remaining contracts held for proprietary trading.
(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.

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     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.

     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 December 31, 2004 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 December 31, 2004 (Dollars are Pre-Tax and in Millions)
	Fair Value of Contracts at December 31, 2004                    Maturities
Source of Fair Value	2005	2006	2007	2008 and  Beyond	Total Fair Value
Proprietary Trading (1)
Actively Quoted (i.e., exchange-traded) prices (2)	$ 0.9	$   -	$   -	$  -	$ 0.9
Prices provided by other external sources (3)	-	-	-	-	-
Modeled	-	-	-	-	-
Total	$ 0.9	$ 0.0	$   -	$  -	$ 0.9
Other Energy Commodity (4)
Actively Quoted (i.e., exchange-traded) prices	$36.4	$0.8	$(1.9)	$0.2	$35.5
Prices provided by other external sources (3)	(35.9)	(0.2)	1.2	-	(34.9)
Modeled (5)	30.8	(5.7)	-	-	25.1
Total	$31.3	$(5.1)	$(0.7)	$0.2	$25.7

Notes:
(1)	Includes all remaining contracts held for proprietary trading.
(2)	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 year 2005.
(3)	Prices provided by other external sources reflect information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms. As of March 2003, Conectiv Energy ceased all proprietary trading activities.
(4)	Includes all SFAS No. 133 hedge activity and non-trading activities marked-to-market through AOCI or on the Statement of Earnings as required. As of the second quarter of 2003, this category also includes the activities of the 24-Hour Power Desk.
(5)	The modeled hedge position is a power swap for 50% of Conectiv Energy's POLR obligation in the DPL territory. 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 ratings of the applicable company are 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 December 31, 2004, a one-level downgrade in the credit rating 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 $135 million. An additional approximately $237 million of aggregate cash collateral or letters of credit would have been required in the event of subsequent downgrades to below investment grad e. PHI and its utility subsidiaries maintain adequate short-term funding sources in the event the additional collateral or letters of credit are required. See "Sources of Capital - Short-Term Funding Sources."

     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 December 31, 2004, Pepco Holdings' subsidiaries engaged in competitive energy activities were in receipt of (a net holder of) cash collateral in the amount of $22.6 million in connection with their competitive energy activities.

     Environmental Remediation Obligations

     PHI's accrued liabilities as of December 31, 2004 include approximately $25.7 million, of which $6.0 million is expected to be incurred in 2005, for potential cleanup and other costs related to sites at which an operating subsidiary is a PRP, is alleged to be a third-party contributor, or has made a decision to clean up contamination on its own property. For information regarding projected expenditures for environmental control facilities, see "Business -- Environmental Matters." The principal environmental remediation obligations as of December 31, 2004, were:

· $7.6 million, of which $1.2 million is expected to be incurred in 2005, payable by DPL in accordance with a consent agreement reached with DNREC during 2001,for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination that resulted from an oil release at the Indian River power plant. That plant was sold on June 22, 2001.

· ACE's planned sale of the B.L. England and Deepwater generating facilities triggered the applicability of the New Jersey Industrial Site Recovery Act requiring remediation at these facilities. When the prospective purchaser of these generating facilities terminated the agreement of sale in accordance with the agreement's termination provisions, ACE decided to continue the environmental investigation process at these facilities. ACE and Conectiv Energy (to which ACE transferred the Deepwater generating facility on February 29, 2004) are continuing the investigation with oversight from NJDEP. ACE anticipates that it will incur costs of approximately $2.6 million in environmental remediation costs, of which $780,000 is expected to be

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	incurred in 2005, associated with the B.L. England generating facility. Conectiv Energy anticipates that it will incur approximately $6.5 million in environmental remediation costs, of which $810,000 is expected to be incurred in 2005, associated with the Deepwater generating facility.
·	As a result of a December 7, 2003 oil spill at the B.L. England generating facility, $811,000 was accrued in December 2003 for estimated clean up, remediation, restoration, and potential NJDEP natural resources damage assessments. As of December 31, 2004, ACE has spent $582,000 for clean up, remediation, and restoration. The remaining liability of $229,000 is anticipated to cover future restoration efforts to be monitored for three years beginning in May 2004. The NJDEP natural resource damage assessments, if any, have not been determined at this time.
·	DPL expects to incur costs of approximately $3.6 million in connection with the Wilmington Coal Gas Site to remediate residual material from the historical operation of a manufactured gas plant. Approximately $2.5 million is expected to be incurred in 2005.
·	Pepco expects to incur approximately $2.1 million for long-term monitoring in connection with Pepco's Swanson Creek oil release, of which $218,000 is expected to be incurred in 2005.

Sources Of Capital

     Pepco Holdings' sources to meet its long-term funding needs, such as capital expenditures, dividends, and new investments, and its short-term funding needs, such as working capital and the temporary funding of long-term funding needs, include internally generated funds, securities issuances and bank financing under new or existing facilities. PHI's ability to generate funds from its operations and to access capital and credit markets is subject to risks and uncertainties. See "Risk Factors" for a discussion of important factors that may impact these sources of capital.

     Internally Generated Cash

     The primary source of Pepco Holdings' internally generated funds is the cash flow generated by its regulated utility subsidiaries in the power delivery business. Additional sources of funds include cash flow generated from its non-regulated subsidiaries and the sale of non-core assets.

     Short-Term Funding Sources

     Pepco Holdings and its regulated utility subsidiaries have traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs but may also be used to temporarily fund long-term capital requirements.

     Pepco Holdings maintains an ongoing commercial paper program of up to $700 million. Pepco, DPL, and ACE have ongoing commercial paper programs of up to $300 million, up to $275 million, and up to $250 million, respectively. The commercial paper notes can be issued with maturities up to 270 days from the date of issue.

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     In July 2004, Pepco Holdings, Pepco, DPL and ACE entered into a five-year credit agreement with an aggregate borrowing limit of $650 million. This agreement replaced a $550 million 364-day credit agreement that was entered into on July 29, 2003. The respective companies also are parties to a three-year credit agreement that was entered into in July 2003 and terminates in July 2006 with an aggregate borrowing limit of $550 million. Pepco Holdings' credit limit under these facilities is $700 million, and the credit limit of each of Pepco, DPL and ACE under these facilities is the lower of $300 million and the maximum amount of short-term debt authorized by the appropriate state commission, except that the aggregate amount of credit utilized by Pepco, DPL and ACE at any given time under these facilities may not exceed $500 million. Funds borrowed under these facilities are available for general corporate purposes. Either credit facility also can be used as credit support for the commercial paper programs of the respective companies. The three-year and five-year credit agreements contain customary financial and other covenants that, if not satisfied, could result in the acceleration of repayment obligations under the agreements or restrict the ability of the companies to borrow under the agreements. Among these covenants is 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 agreements. As of December 31, 2004, the applicable ratios for Pepco Holdings, Pepco, DPL and ACE were 59.0%, 58.5%, 52.1% and 50.2%, respectively. The credit agreements also contain a number of customary events of default that could result in the acceleration of repayment obligations under the agreements, including (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 agreements) of Pepco Holdings or the failure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE.

     In December 2004, PHI entered into a $50 million term loan due December 13, 2005 with a bank. The loan is variable rate, based on LIBOR. PHI has the option to select interest periods based on one, two, three or six month LIBOR rates. The covenants in the agreement are substantially consistent with those found in the three-year and five-year credit agreements. Proceeds from the loan were used to pay down commercial paper.

     Long-Term Funding Sources

     The sources of long-term funding for PHI and its subsidiaries are the issuance of debt and equity securities and borrowing under long-term credit agreements. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures and new investments, and to refund or refinance existing securities.

PUHCA Restrictions

     Because Pepco Holdings is a public utility holding company registered under the Public Utility Holding Company Act (PUHCA), it must obtain SEC approval to issue securities. PUHCA also prohibits Pepco Holdings from borrowing from its subsidiaries. Under an SEC Financing Order dated July 31, 2002 (the Financing Order), Pepco Holdings is authorized to issue equity, preferred securities and debt securities in an aggregate amount not to exceed $3.5 billion through an authorization period ending June 30, 2005, subject to a ceiling on the effective cost of these funds. Pepco Holdings is also authorized to enter into guarantees to third parties or otherwise provide credit support with respect to obligations of its subsidiaries for up to $3.5

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billion. Of this amount, only $1.75 billion may be on behalf of subsidiaries engaged in energy marketing activities.

     Pepco Holdings may issue common stock to satisfy its obligations under its Shareholder Dividend Reinvestment Plan and various employee benefit plans. Under the Financing Order, Pepco Holdings is limited to issuing no more than an aggregate of 20 million shares of common stock under its Shareholder Dividend Reinvestment Plan and employee benefit plans during the period ending June 30, 2005.

     The Financing Order requires that, in order to issue debt or equity securities, including commercial paper, Pepco Holdings must maintain a ratio of common stock equity to total capitalization (consisting of common stock, preferred stock, if any, long-term debt and short-term debt) of at least 30 percent. At December 31, 2004, Pepco Holdings' common equity ratio for purposes of the Financing Order was 36.6 percent. The Financing Order also requires that all rated securities issued by Pepco Holdings be rated "investment grade" by at least one nationally recognized rating agency. Accordingly, if Pepco Holdings' common equity ratio were less than 30 percent or if no nationally recognized rating agency rated a security investment grade, Pepco Holdings could not issue the security without first obtaining an amendment to the Financing Order from the SEC.

     If an amendment to the Financing Order is required to enable Pepco Holdings or any of its subsidiaries to effect a financing, there is no certainty that such an amendment could be obtained or as to the timing of SEC action. The failure to obtain timely relief from the SEC, in such circumstances, could have a material adverse effect on the financial condition of Pepco Holdings and its subsidiaries.

     The foregoing financing limitations also generally apply to Pepco, DPL, ACE and certain other Pepco Holdings' subsidiaries.

     On February 15, 2005, PHI and its subsidiaries filed an application with the SEC for authorization to engage in various financing activities described therein for an authorization period through June 30, 2008.

Money Pool

     Under the July 31, 2002 Financing Order, Pepco Holdings has received SEC authorization under PUHCA to establish the Pepco Holdings system money pool. The money pool is a cash management mechanism used by Pepco Holdings to manage the short-term investment and borrowing requirements of the PHI subsidiaries that participate in the money pool. Pepco Holdings may invest in but not borrow from the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by Pepco Holdings. Eligible subsidiaries with cash requirements may borrow from the money pool. Borrowings from the money pool are unsecured. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on Pepco Holdings' short-term borrowing rate. Pepco Holdings deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowin g needs of its participants, which may require Pepco Holdings to borrow funds for deposit from external sources. Consequently, Pepco Holdings' external borrowing requirements fluctuate based on the amount of funds required to be deposited in the money pool.

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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., pursuant to an Asset Purchase and Sale Agreement. As part of the Asset Purchase and Sale Agreement, Pepco entered into several ongoing contractual arrangements with Mirant 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).

     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 currently 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 have arisen or 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 standard offer service obligations in Maryland through June 2004 and its standard offer service 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 that 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 current plan of reorganization filed by the Mirant entities with the Bankruptcy Court, certain Mirant entities other than Mirant Corporation would pay significantly higher portions 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

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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 an agreement with Panda, entered into in 1991, Pepco is obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (the Panda PPA). 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 Oblig ations).

     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 which 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 this uncertainty, Pepco, in the third quarter of 2003, expen sed $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 amou nt ultimately recovered could be higher or lower.

     Mirant's Attempt to Reject the PPA-Related Obligations

     On August 28, 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

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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). On August 4, 2004, the Court of Appeals remanded the case to the District Court saying that the District Court has 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 judgment 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 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, 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.

     As more fully discussed below, Mirant had been making regular periodic payments in respect of the PPA-Related Obligations. On December 9, 2004, Mirant filed a notice with the Bankruptcy Court that it was suspending payments to Pepco in respect of the PPA-Related Obligations. On December 13, 2004, Mirant failed to make a payment of approximately $17.9 million due to Pepco for the period November 1, 2004 to November 30, 2004. Mirant failed to make that payment. On December 23, 2004, Pepco received a payment of approximately $6.8 million from Mirant, which according to Mirant represented the market value of the power for which payment was due on December 13. Mirant has informed Pepco that it intends to continue to pay the market value, but not the above-market portion, of the power purchased under the PPA-Related Obligations. Pepco disagrees with Mirant's assertion that it need only pay the market value and believes that the amount repr esenting the market value calculated by Mirant is insufficient.

     On January 21, 2005, Mirant made a approximately $21.1 million, which, according to Mirant, includes the payment for the FirstEnergy PPA for December 2004 and "includes the December 2004 TPA revenue in the amount of $29,093,173.43, the TPA costs in the amount of $37,865,924.10, and an allocated share of [FirstEnergy's] PPA bill credits/charges in the amount of $5,490,164.79." Pepco disputes Mirant's contention that the amount paid reflects the full amount due Pepco under these agreements for the applicable periods.

     As of March 1, 2005, Mirant has withheld payment of approximately $34.8 million due to Pepco under 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. On March 1, 2005 (as amended by order dated March 7, 2005), the District Court granted Pepco's motion to withdraw jurisdiction over the Asset Purchase and Sale Agreement rejection proceedings from the Bankruptcy Court. In addition, the District Court ordered Mirant to pay on March 18, 2005, all past-due unpaid amounts under the PPA-Related Obligations. Mirant has filed a motion for reconsideration and a stay of the March 1, 2005 order.

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     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 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 $133.2 million as of March 1, 2005 (assuming Mirant continues to withhold unpaid amounts of approximately $34.8 million as of March 1, 2005.

     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 March 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 March 1, 2005, at the rates provided in the PPA (with an average price per kilowatt hour of approximately 6.0 cents) and resold the capacity and energy at market rates projected, given the characteristics of the FirstEnergy PPA, to be approximately 5.0 cents per kilowatt hour, Pepco estimates that it would cost approximately $31 million for the remainder of 2005, the final year of the FirstEnergy PPA.

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· If Pepco were required to purchase capacity and energy from Panda commencing as of March 1, 2005, at the rates provided in the PPA (with an average price per kilowatt hour of approximately 16.9 cents), and resold the capacity and energy at market rates projected, given the characteristics of the Panda PPA, to be approximately 7.4 cents per kilowatt hour, Pepco estimates that it would cost approximately $29 million for the remainder of 2005, approximately $34 million in 2006 and 2007, and approximately $34 million to $49 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.

     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 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 distribution rates. If Pe pco'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. However, the accounting treatment of such a loss depends on a number of legal and regulatory factors, and is not determinable at this time.

     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.

     On March 15, 2004, Mirant filed a complaint with the Bankruptcy Court seeking a declaratory judgment that the facility and capacity credit

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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.

Federal Tax Treatment of cross-border Leases

     PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which as of December 31, 2004 had a book value of approximately $1.2 billion. 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 that the IRS intends to challenge on various grounds the purported tax benefits claimed by taxpayers enteri ng into certain sale-leaseback transactions with tax indifferent parties, including those entered into on or prior to March 12, 2004 (the Notice).

     PCI's cross-border energy leases are similar to those sale-leaseback transactions described in the Notice. PCI's leases are currently under examination by the IRS as part of the normal PHI tax audit. PHI believes there is a substantial likelihood that the IRS will challenge the tax benefits realized from interest and depreciation deductions claimed by PCI with respect to these leases, or the timing of these benefits, for the years 2001 through 2004. The tax benefits claimed by PCI for these years were approximately $175 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 deferral of tax benefits that does not change the total estimated net income from PHI's leases does not require an adjustment to the book value of the leases. 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.

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     In recent deliberations, The Financial Accounting Standards Board (FASB) has determined that a change in the timing of tax benefits also should require a repricing of the lease and an adjustment to the book value of a lease. Under this interpretation, 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. PHI understands that the FASB intends to publish this guidance for comment in the near future to become effective at the end of 2005. If adopted, the application of this guidance could result in a material adverse effect on PHI's results of operations even if the resolution is limited to a deferral of the tax benefits realized by PCI from its leases.

Rate Proceedings

     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. The petition was based on actual data for the nine months ended September 30, 2002, and forecasted data for the three months ended December 31, 2002 and sought an overall rate increase of approximately $68.4 million, consisting of an approximately $63.4 million increase in electricity distribution rates and $5 million for recovery of regulatory assets through the RARC. In October 2003, ACE filed an update supporting an overall rate increase of approximately $41.3 million, consisting of a $36.8 million increase in electricity distribution rates and a RARC of $4.5 million. This petition was ACE's first increase request for electric distribution rates since 1991. The requested increase would apply to all rate schedules in ACE's tariff. The Ratepayer Advocate filed testimony on January  3, 2004, proposing an annual rate decrease of $11.7 million. Intervenor groups representing industrial users and local generators filed testimony that did not take a position with respect to an overall rate change but their proposals, if implemented, would affect the way in which an overall rate increase or decrease would be applied to the particular rates under which they receive service. ACE's rebuttal testimony, filed in February 2004, made some changes to its October filing and proposed an overall rate increase of approximately $35.1 million, consisting of a $30.6 million increase in distribution rates and a $4.5 million increase in the RARC. Hearings were held before an Administrative Law Judge in late March, early April and May 2004. At the hearing held in April 2004, the Ratepayer Advocate proposed an annual rate decrease of $4.5 million, modifying its earlier proposal that rates be decreased by $11.7 million annually. The Ratepayer Advocate and Staff of the NJBPU filed their briefs in this proceeding in August 2004. The Ratepayer Advocate's brief supported its earlier proposal of an annual rate decrease of $4.5 million. The Staff's brief, however, stated for the first time its position calling for an overall decrease of $10.8 million. Reply briefs were filed on August 23, 2004. Settlement discussions between ACE, the NJBPU Staff and the Ratepayer Advocate have been ongoing.

     On December 12, 2003, the NJBPU issued an order also consolidating outstanding issues from several other proceedings into the base rate case proceeding. On December 22, 2003, ACE filed a Motion for Reconsideration in which it suggested that these issues be dealt with in a Phase II to the base rate case to address the outstanding issues identified in the December 12, 2003 Order. After discussion with the parties to the base rate case, it was agreed that a Phase II to the base rate case to address these issues, along with the $25.4 million of deferred restructuring costs previously transferred into the base rate case, would be initiated in April 2004. On April 15, 2004, ACE filed testimony with the NJBPU initiating a Phase II to the base rate proceeding described above. The parties to this case have

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been actively engaged in settlement discussions in conjunction with settlement of Phase I issues.

     On August 31, 2004, ACE filed requests with the NJBPU proposing changes to its Transition Bond Charge, its Market Transition Charge - Tax rate, and its BGS Reconciliation charges. The net impact of these rate changes is to decrease ACE's annual revenues by approximately 1.5%. All of these rate changes were implemented on October 1, 2004.

     On October 1, 2004, DPL submitted its annual Gas Cost Rate (GCR) filing to the 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, on November 29, 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 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. A final order addressing both the Nov ember 1 and December 29 increases is expected in the spring of 2005.

     On February 13, 2004, DPL filed with the DPSC for a change in electric ancillary service rates that would have an aggregate effect of increasing annual Delaware electric revenues by $13.1 million or 2.4%. This filing was prompted by the increasing ancillary service costs charged to DPL by PJM. The proposed rates went into effect on March 15, 2004, subject to refund. On June 22, 2004, the DPSC approved a settlement agreement that provided for an increase having an aggregate effect of increasing annual Delaware electric revenues by $12.4 million, or 2.3%, with rates effective June 23, 2004. The approved increase was slightly less than the proposed increase that went into effect on March 15, 2004. As part of the settlement, the resulting estimated over-collection of $75,000 was given by DPL to the State of Delaware Low Income Fund administered by the Delaware Department of Human Services on July 15, 2004.

     In compliance with the settlement approved by the MPSC in connection with the merger of Pepco and Conectiv, on December 4, 2003, DPL and Pepco submitted testimony and supporting schedules to review and reset if necessary its electricity distribution rates in Maryland to be effective July 1, 2004, when the then-current distribution rate freeze/caps ended. DPL's filing demonstrated that it was in an under-earning situation and, as allowed in the merger settlement, DPL requested that a temporary rate reduction implemented on July 1, 2003 for non-residential customers be terminated effective July 1, 2004. DPL estimated that the termination of the rate reduction would increase its annual revenues by approximately $1.1 million. A settlement reached between the parties allowing for this $1.1 million increase to be effective July 1, 2004 was approved by the MPSC in Order No. 79186. With limited exceptions, DPL cannot increase its distribution rates until January 1, 2007.

     Pepco's filing demonstrated that it also was in an under-earning situation. However the merger settlement provided that Pepco's distribution rates after July 1, 2004 could only remain the same or be decreased. With limited exceptions, Pepco cannot increase its distribution rates until January 1, 2007. In an order dated July 6, 2004 the MPSC affirmed the

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Hearing Examiner's recommendation that no rate decrease was warranted at that time.

     On July 3, 2004, Pepco filed a distribution rate review case with the DCPSC as required by the terms of the Pepco-Conectiv merger settlement approved by the DCPSC. This case will determine whether Pepco's distribution rates will be decreased. In accordance with the terms of the merger settlement, Pepco's distribution rates cannot be increased as a result of the case. On November 24, 2004, the DCPSC issued an order that designated the issues to be considered in the case and set the hearing schedule. On December 17, 2004, Pepco filed supplemental direct testimony addressing the DCPSC-designated issues. Pepco's filings indicate that no rate decrease is warranted. On March 4, 2005, the DCPSC issued an order granting a joint motion filed on March 3, 2005, on behalf of Pepco and several other parties in the case to suspend the procedural schedule to allow the parties to focus on completing settlement discussions. In the joint motion, the movin g parties informed the DCPSC that they had agreed in principle to settlement provisions that would resolve all issues in the proceeding and that a settlement agreement could be filed in the near future.

Restructuring Deferral

     Pursuant to a July 1999 summary order issued by the NJBPU under the New Jersey Electric Discount and Energy Competition Act (EDECA) (which was subsequently affirmed by a final decision and order issued in March 2001), ACE was obligated to provide basic generation service (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 Ener gy Adjustment Clause and ACE's Demand Side Management Programs. ACE established a regulatory asset in an amount equal to the balance.

     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.

     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) transferred to ACE's 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

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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 Appellate Division of the Superior Court of New Jersey, which hears appeals of New Jersey administrative agencies, including the NJBPU, a Notice of Appeal related to the July 2004 final order. 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 on July 31, 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. 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. On March 4, 2003, theInternal Revenue S ervice (IRS) issued a notice of proposed rulemaking (NOPR)that is relevant to that principal issue.Comments on the NOPR were filed byseveral parties on June 2, 2003, and the IRS held a public hearing on June 25,2003.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 thecourts have held and the IRS has stated that proposed rules are notauthoritative and that no decision should be issued on the basis of proposedrules. Instead, Pepco argued that the only prudent course of action is for the DCPSC to await the issuance of final regulations relating to the taxissues and then 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 adoptregulations. Other issues in the proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.

     Pepco believes that a sharing of EDIT and ADITC would violate the 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 ADITC balance, 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 December 31, 2004, the District of Columbia jurisdictional transmission and distribution-related ADITC balance was approximately $6.0 million.

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     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 D.C. 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. Reply briefs were filed in May 2002. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that was raised in the D.C. case. As of December 31, 2004, 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, 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 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 operative. As of December 31, 2004, the Maryland retail jurisdiction al transmission and distribution-related ADITC balance was approximately $10.7 million. The Hearing Examiner decided all other issues in favor of Pepco, except 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 4, 2003 IRS NOPR.

     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

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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 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.

SOS and Default Service Proceedings

     District of Columbia

     In February 2003, the DCPSC opened a new proceeding to consider issues relating to (a) the establishment of terms and conditions for providing SOS in the District of Columbia after Pepco's obligation to provide SOS terminated on February 7, 2005, and (b) the selection of a new SOS provider.

     In December 2003, the DCPSC issued an order that set forth the terms and conditions for the selection of a new SOS provider(s) and the provision of SOS by Pepco on a contingency basis. In December 2003, the DCPSC also issued an order adopting terms and conditions that would apply if Pepco continued as the SOS provider after February 7, 2005. In March 2004, the DCPSC issued an order adopting the wholesale SOS model,i.e., Pepco would continue to be the SOS provider in the District of Columbia after February 7, 2005. This March 2004 order, as amended by a DCPSC order issued in July 2004, extends Pepco's obligation to provide default electricity supply at market rates for up to an additional 76 months for small commercial and residential customers, and for an additional 28 months for large commercial customers.

     In August 2004, the DCPSC issued an order adopting administrative charges for residential, small and large commercial DC SOS customers that are intended to allow Pepco to recover the administrative costs incurred to provide the SOS supply. The approved administrative charges include an average margin for Pepco of approximately $0.00248 per kilowatt hour, calculated based on total sales to residential, small and large commercial DC SOS customers over the twelve months ended December 31, 2003. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of DC SOS customers from each customer class and the load taken by such customers over the time period. The administrative charges went into effect for Pepco's DC SOS sales on February 8, 2005. Pepco completed the first competitive procurement process for DC SOS at the end of October and filed the proposed new SOS rates with the DC PSC on November 3, 2004.

     The TPA with Mirant under which Pepco obtained the fixed-rate DC 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 DC 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 DC SOS rates charged to customers during the period from January 23 through January 31, 2005. In addition, because the new DC 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 DC SOS contracts and the DC SOS rates charged to customers for the period from February 1 to February 7, 2005. The total amount of the diff erence is estimated to be approximately $8.7 million. This difference, however, will

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be included in the calculation of the Generation Procurement Credit (GPC) for DC 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 recovery 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.

     Maryland

     Under a settlement approved by the MPSC in April 2003 addressing SOS service in Maryland following the expiration of Pepco's fixed-rate default supply obligations in July 2004, Pepco is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customers through May 2006, and to large commercial customers through May 2005. In accordance with the settlement, Pepco purchases the power supply required to satisfy its market rate default supply obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved by the MPSC. Pepco is entitled to recover from its default supply customers the cost of the default supply plus an average margin of $0.002 per kilowatt hour, calculated based on total sales to residential, small and large commercial Maryland SOS customers over the twelve months ended December 31, 200 3. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of Maryland SOS customers from each customer class and the load taken by such customers over the time period.

     Under a settlement approved by the MPSC in April 2003 addressing SOS service in Maryland following the expiration of DPL's fixed-rate default supply obligations to non-residential customers in June 2004 and to residential customers through June 2004, DPL is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customers through May 2006, and to large commercial customers through May 2005. In accordance with the settlement, DPL purchases the power supply required to satisfy its market rate default supply obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved and supervised by the MPSC. DPL is entitled to recover from its default supply customers the costs of the default supply plus an average margin of $0.002 per kilowatt hour, calculated based on total sales to residential, small, and large commercial Maryland SOS customers over the twelve months ended December 31, 2003. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of Maryland SOS customers from each customer class and the load taken by such customers over the time period.

     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 VSCC. DPL currently obtains all of the energy and capacity needed to fulfill its default service obligations in Virginia under a supply

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agreement with Conectiv Energy. A prior agreement, also with Conectiv Energy, terminated effective December 31, 2004. The current contract was entered into after conducting a competitive bid procedure identical to the Maryland SOS process in most respects and Conectiv Energy was the lowest bidder to provide wholesale power supply for DPL's Virginia default service customers. The new supply agreement commenced January 1, 2005 and expires in May 2006. On October 26, 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 dated November 17, 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 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 17 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 Office of Attorney General. The VSCC ruled on January 18, 2005, that the administrative charge and margin are base rate items not recoverable through a fuel clause. No appeal is planned regarding this filing. A settlement resolving all other issues and m aking the interim rates final was filed on March 4, 2005, contingent only on possible future adjustment depending on the result of a related proceeding at FERC. A hearing is scheduled for March 16, 2005, and the VSCC is expected to approve the settlement.

     Also in October, DPL and Conectiv Energy jointly filed an application with the VSCC under Virginia's Affiliates Act requesting authorization for DPL to enter into a contract to purchase power from an affiliate. This authorization permits the contract to be executed with an affiliate, but is not a ruling on the merits of the contract. A VSCC order dated December 17, 2004 granted approval for DPL to purchase power from Conectiv Energy under the new contract according to its terms beginning January 1, 2005.

     On October 29, 2004, Conectiv Energy made a filing with FERC requesting authorization to enter into a contract to supply power to an affiliate. On December 30, 2004, FERC granted the requested authorization effective January 1, 2005, subject to refund and hearings on the narrow question whether, in 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 unduly favored Conectiv Energy in the credit criteria and analysis applied. DPL cannot predict the outcome of this proceeding.

     Delaware

     Under a settlement approved by the DPSC, DPL is required to provide default electricity supply to customers in Delaware until May 1, 2006. On October 19, 2004, the DPSC initiated a proceeding to investigate and determine which entity should act as the standard offer supplier in DPL's Delaware service territory after May 1, 2006, and what prices should be charged for SOS after May 1, 2006. Similar to the process used in Maryland, 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 will resolve issues relating to the process under which supply will be

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acquired by the SOS provider and way in which SOS prices will be set and monitored. In the last stage, 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 February 22, 2005, the DPSC voted to approve an SOS process that will allow a Wholesale Standard Offer Service Model with DPL as the SOS Provider. Issues including the length of this extension and any profit margin that DPL may be able to earn and retain in conjunction with this service have been deferred for further discussion and will be decided by the DPSC at a later date. A written DPSC order documenting this decision is expected sometime in March or April 2005.

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

     Pursuant to a September 25, 2003 NJBPU order, ACE filed a report on April 30, 2004 with the NJBPU recommending that the B.L. England generating facility be shut down in accordance with the terms of an April 26, 2004 preliminary settlement agreement among PHI, Conectiv and ACE, NJDEP and the Attorney General of New Jersey. The report stated that the operation of the B.L. England facility is necessary at the present time to satisfy reliability standards, but that those reliability standards could also be satisfied in other ways. The report concludes 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 lines into southern New Jersey. ACE cannot predict whether the NJBPU will approve the construction of the additional transmission lines.

     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 the transmission upgrades necessary to maintain reliability in the Atlantic zone after the retirement of B.L. England. 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 re cover 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 FERC and the state regulatory commissions and, therefore, cannot predict the financial impact to ACE of installing the recommended transmission upgrades. However, in the event that the NJBPU makes satisfactory findings and grants other requested approvals concerning the retirement of B.L. England and approves the construction of the transmission upgrades required to maintain reliability in the Atlantic zone after such retirement, 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.

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     On November 1, 2004, ACE made a filing with the NJBPU requesting approval of the transmission upgrades required to maintain reliability in the Atlantic zone after the retirement of B.L. England. On December 22, 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 cannot predict the outcome of these two proceedings.

     On November 12, 2004, ACE made a filing with the NJBPU requesting approval of year 2005 capital projects with respect to B.L. England. This filing was made pursuant the September 25, 2003 B.L. England rate order, which established a requirement that ACE file for approval of capital expenditures in excess of $1 million. For 2005, four projects, totaling $3.2 million in capital expenditures, have been identified as necessary to allow continued operation of B.L. England until its retirement. Two of these projects are well below the $1 million threshold set forth in the September 25, 2003 NJBPU order and two are above that threshold. ACE cannot predict the outcome of this proceeding.

General Litigation

     Asbestos

     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, plaintiffs argue 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

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unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco's and PHI's results of operations.

     Enron

     On December 2, 2001, Enron North America Corp. and several of its affiliates (collectively, Enron) filed for protection under the United States Bankruptcy Code. In December 2001, DPL and Conectiv Energy terminated all energy trading transactions under various agreements with Enron. In late January 2003, after several months of discussions between the parties concerning the amount owed by DPL and Conectiv Energy, Enron filed an adversary complaint against Conectiv Energy in the Bankruptcy Court for the Southern District of New York. The complaint sought, among other things, damages in the amount of approximately $11.7 million.

     On June 3, 2004, the Bankruptcy Court approved a settlement among Enron, Conectiv Energy and DPL pursuant to which Conectiv Energy paid Enron an agreed settlement amount that was less than the $11.7 million damages Enron sought and the parties released all claims against each other. Conectiv Energy had previously established a reserve in an amount equal to the agreed settlement payment. Accordingly, the settlement did not have an effect on earnings.

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 CERCLA at the Diamond State Salvage site in Wilmington, Delaware. In the context of the negotiations, DOJ informed DPL that DPL is a de minimis party at the site. In February 2005, DPL entered into a de minimis consent decree with the United States which, if approved by the U.S. District Court, would require DPL to pay $144,000 as reimbursement of the government's response costs, resolve DPL's alleged liability, and provide DPL a covenant not to sue from the United States and protection from third-party claims for contribution.

     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

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reached with the MDE. DPL expects to complete the RI/FS in the first quarter of 2005.

     In October 1995, each of Pepco and DPL received notice from EPA that it, along with several hundred other companies, might be a 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 this site. Under the terms of the consent decree, which was approved by the U.S. District Court for the District of Maryland on March 31, 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 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. On May 12, 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. On October 2, 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 December 31, 2004, Pepco had accrued $1.7 million to meet its liability for a site remedy. 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.

     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 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

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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.

     On April 7, 2000, approximately 139,000 gallons of oil leaked from a pipeline at a generation station that was owned by Pepco at Chalk Point Generating Station in Aquasco, Maryland. The pipeline was operated by Support Terminals Services Operating Partnership LP (ST Services), an unaffiliated pipeline management company. The oil spread from Swanson Creek to the Patuxent River and several of its tributaries. The area affected covers portions of 17 miles of shoreline along the Patuxent River and approximately 45 acres of marshland adjacent to the Chalk Point property.

     In December 2000, the Department of Transportation, Office of Pipeline Safety, Research and Special Programs Administration (OPS) issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (NOPV). The NOPV alleged various deficiencies in compliance with regulations related to spill reporting, operations and maintenance of the pipeline and record keeping, none of which relate to the cause of the spill. The NOPV was issued to both Pepco and ST Services and proposed a civil penalty in the amount of $674,000. On June 2, 2004, the OPS issued a Final Order regarding the NOPV in this matter. The Final Order assessed a total fine of $330,250, with $256,250 of that amount assessed jointly against Pepco and ST Services and the remaining $74,000 assessed solely against ST Services. ST Services subsequently filed a Petition for Reconsideration. All penalties were stayed pending the outcome of the Petition for Rec onsideration. On February 9, 2005, OPS issued a Decision on the Petition for Reconsideration that affirmed the Final Order. Pepco's share of the $330,250 penalty assessed pursuant to the Final Order amounts to $128,125.

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

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Conectiv Energy facilities in New Jersey. Among other things, the preliminary settlement agreement provides that:

· contingent upon the receipt of necessary approvals from the NJBPU, PJM, 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 SO₂, 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 re quired 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. Englandgenerating station 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.

· to resolve any possible civil liability (and without admitting liability) for violations of the permit provisions of the New Jersey APCA and the PSD provisions of the 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 necessary to satisfy the EPA's new cooling water intake structure regulations in accordance with a schedule that NJDEP will establish in the renewal NJPDES permit for the B.L. England facility. The schedule will take 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.

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     The preliminary settlement agreement also 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.

CRITICAL ACCOUNTING POLICIES

General

     The SEC has defined a company's most critical accounting policies as the ones that are most important to the portrayal of its financial condition and results of operations, and which require the company to make its most difficult and subjective judgments, often as a result of the need to make estimates of matters that are inherently uncertain. Critical estimates represent those estimates and assumptions that may be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and that have a material impact on financial condition or operating performance.

Accounting Policy Choices

     Pepco Holdings' management believes that based on the nature of the businesses in which its subsidiaries are primarily engaged, Pepco Holdings has very little choice regarding many of the accounting policies it utilizes. In that regard, the most significant portion of Pepco Holdings' business consists of its regulated utility operations, which are subject to the provisions of Statement of Financial Accounting Standards (SFAS) No. 71 "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 does allow regulated entities, in appropriate circumstances, to establish regulatory assets and regulatory liabilities and to defer the income statement impact of certain costs that are expected to be recovered in future rates. However, management believes that in the areas that Pepco Holdings is afforded accounting policy choices, its selection from among the alternatives available generally would not have a material impact on the Compan y's financial condition or results of operations.

     Use of Estimates

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America, such as Statement of Position 94-6 "Disclosure of Certain Significant Risks and Uncertainties," requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes.

     Examples of significant estimates used by Pepco Holdings include the assessment of contingencies and the need/amount for reserves of future receipts from Mirant (refer to the "Relationship with Mirant" section, herein), the calculation of future cash flows and fair value amounts for use in goodwill and asset impairment evaluations, fair value calculations (based on estimating market pricing) associated with derivative instruments, pension and other post-retirement benefits assumptions, unbilled revenue calculations, and judgment involved with assessing the probability of recovery of regulatory assets. Additionally, PHI is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of our business. We record an estimated liability for these proceedings and claims based upon the probable and reasonably estimatable

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criteria contained in SFAS No. 5 "Accounting for Contingencies." Although Pepco Holdings believes that its estimates and assumptions are reasonable, they are based upon information presently available. Actual results may differ significantly from these estimates.

     Goodwill Impairment Evaluation

     Pepco Holdings believes that the estimates involved in its goodwill impairment evaluation process represent "Critical Accounting Estimates" because they (i) may be susceptible to change from period to period because management is required to make assumptions and judgments about the discounting of future cash flows, which are inherently uncertain, (ii) actual results could vary from those used in Pepco Holdings' estimates and the impact of such variations could be material, and (iii) the impact that recognizing an impairment would have on Pepco Holdings' assets and the net loss related to an impairment charge could be material.

     The provisions of SFAS No. 142, "Goodwill and Other Intangible Assets," require the evaluation of goodwill for impairment at least annually or more frequently if events and circumstances indicate that the asset might be impaired. SFAS No. 142 indicates that if the fair value of a reporting unit is less than its carrying value, including goodwill, an impairment charge may be necessary. Pepco Holdings' goodwill that was generated in the transaction by which Pepco acquired Conectiv in 2002 was allocated to Pepco Holdings' Power Delivery segment. In order to estimate the fair value of its Power Delivery segment, Pepco Holdings discounts the estimated future cash flows associated with the segment using a discounted cash flow model with a single interest rate that is commensurate with the risk involved with such an investment. The estimation of fair value is dependent on a number of factors, including but not limited to interest rates, future growth assumptions, operating and capital expenditure requirements and other factors, changes in which could materially impact the results of impairment testing. Pepco Holdings tested its goodwill for impairment as of July 1, 2004. This testing concluded that Pepco Holdings' goodwill balance was not impaired. A hypothetical decrease in PHI Power Delivery segment's forecasted cash flows of 10 percent would not have resulted in an impairment charge.

     Long Lived Assets Impairment Evaluation

     Pepco Holdings believes that the estimates involved in its long-lived asset impairment evaluation process represent "Critical Accounting Estimates" because they (i) are highly susceptible to change from period to period because management is required to make assumptions and judgments about undiscounted and discounted future cash flows and fair values, which are inherently uncertain, (ii) actual results could vary from those used in Pepco Holdings' estimates and the impact of such variations could be material, and (iii) the impact that recognizing an impairment would have on Pepco Holdings' assets as well as the net loss related to an impairment charge could be material.

     SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" requires that certain long-lived assets must be tested for recoverability whenever events or circumstances indicate that the carrying amount may not be recoverable. An impairment loss shall only be recognized if the carrying amount of an asset is not recoverable and the carrying amount exceeds its fair value. The asset is deemed to not be recoverable when its carrying amount exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. In order to estimate an asset's future cash flows, Pepco Holdings considers

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historical cash flows. Pepco Holdings uses its best estimates in making these evaluations and considers various factors, including forward price curves for energy, fuel costs, legislative initiatives, and operating costs. The process of determining fair value is done consistent with the process described in assessing the fair value of goodwill, discussed above.

     Derivative Instruments

     Pepco Holdings believes that the estimates involved in accounting for its derivative instruments represent "Critical Accounting Estimates" because (i) the fair value of the instruments are highly susceptible to changes in market value and interest rate fluctuations, (ii) there are significant uncertainties in modeling techniques used to measure fair value in certain circumstances, (iii) actual results could vary from those used in Pepco Holdings' estimates and the impact of such variations could be material, and (iv) changes in fair values and market prices could result in material impacts to Pepco Holdings' assets, liabilities, other comprehensive income (loss), and results of operations. Refer to Note 2, Summary of Significant Accounting Policies - Accounting for Derivatives, herein, for information on PHI's accounting for derivatives.

     Pepco Holdings and its subsidiaries use derivative instruments primarily to manage risk associated with commodity prices and interest rates. SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities," as amended,governs the accounting treatment for derivatives and requires that derivative instruments be measured at fair value. The fair value of derivatives is determined using quoted exchange prices where available. For instruments that are not traded on an exchange, external broker quotes are used to determine fair value. For some custom and complex instruments, an internal model is used to interpolate broker quality price information. Models are also used to estimate volumes for certain transactions. The same valuation methods are used to determine the value of non-derivative, commodity exposure for risk management purposes.

     Pension and Other Post-retirement Benefit Plans

     Pepco Holdings believes that the estimates involved in reporting the costs of providing pension and other post-retirement benefits represent "Critical Accounting Estimates" because (i) they are based on an actuarial calculation that includes a number of assumptions which are subjective in nature, (ii) they are dependent on numerous factors resulting from actual plan experience and assumptions of future experience, and (iii)changes in assumptions could impact Pepco Holdings' expected future cash funding requirements for the plans and would have an impact on the projected benefit obligations, the reported pension and other post-retirement benefit liability on the balance sheet, and the reported annual net periodic pension and other post-retirement benefit cost on the income statement. In terms of quantifying the anticipated impact of a change in assumptions, Pepco Holdings estimates that a .25% change in the discount rate used to value the benef it obligations could result in a $5 million impact on its consolidated balance sheets and income statements. Additionally, Pepco Holdings estimates that a .25% change in the expected return on plan assets could result in a $4 million impact on the consolidated balance sheets and income statements and a .25% change in the assumed healthcare cost trend rate could result in a $.5 million impact on its consolidated balance sheets and income statements. Pepco Holdings' management consults with its actuaries and investment consultants when selecting its plan assumptions.

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     Pepco Holdings follows the guidance of SFAS No. 87, "Employers' Accounting for Pensions," and SFAS No. 106, "Employers' Accounting for Post-retirement Benefits Other Than Pensions," when accounting for these benefits. Under these accounting standards, assumptions are made regarding the valuation of benefit obligations and the performance of plan assets. In accordance with these standards, the impact of changes in these assumptions and the difference between actual and expected or estimated results on pension and post-retirement obligations is generally recognized over the working lives of the employees who benefit under the plans rather than immediately recognized in the income statement. Plan assets are stated at their market value as of the measurement date, December 31.

     Regulation of Power Delivery Operations

     The requirements of SFAS No. 71 apply to the Power Delivery businesses of Pepco, DPL, and ACE. Pepco Holdings believes that the judgment involved in accounting for its regulated activities represent "Critical Accounting Estimates" because (i) a significant amount of judgment is required (including but not limited to the interpretation of laws and regulatory commission orders) to assess the probability of the recovery of regulatory assets, (ii) actual results and interpretations could vary from those used in Pepco Holdings' estimates and the impact of such variations could be material, and (iii) the impact that writing off a regulatory asset would have on Pepco Holdings' assets and the net loss related to the charge could be material.

New Accounting Policies Issued

SFAS 123R

     In December 2004, the FASB issued Statement No. 123 (revised 2004), "Share-Based Payment" which establishes standards for the accounting for transactions in which an entity exchanges its equity instruments primarily for employee services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity's equity instruments or that may be settled by the issuance of those equity instruments. In most cases, FAS 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award and to recognize that cost over the service period, normally the vesting period. FAS 123R will be effective for Pepco Holdings as of the July 1, 2005. Pepco Holdings is in the process of evaluating the impact of FAS 123R and does not anticipate that its implementation will hav e a material effect on its overall financial position or net results of operations.

RISK FACTORS

     The business of PHI and its subsidiaries are subject to numerous risks and uncertainties, including the events or conditions identified below. 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.

PHI and its subsidiaries are subject to substantial governmental regulation. If PHI or any of its subsidiaries receives unfavorable regulatory treatment, PHI's business could be negatively affected.

     PHI is a registered public utility holding company that is subject to regulation by the SEC under PUHCA. As a registered public utility holding

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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.

     The utility businesses conducted by PHI's power delivery subsidiaries are subject to regulation by various federal, state and local regulatory agencies that significantly affects their operations. Each of Pepco, DPL and ACE is regulated by public service commissions in its service territories, with respect to, among other things, the rates it can charge retail customers for the delivery of electricity. In addition, the rates that the companies can charge for electricity transmission are regulated by FERC. The companies cannot change delivery or transmission rates without approval by the applicable regulatory authority. While the approved delivery and transmission rates are intended to permit the companies to recover their costs of service and earn a reasonable rate of return, the profitability of the companies is affected by the rates they are able to charge. In addition, if the costs incurred by any of the companies in operating it s transmission and distribution facilities exceed the allowed amounts for costs included in the approved rates, the financial results of that company, and correspondingly, PHI, will be adversely affected.

     PHI's subsidiaries also are required to have numerous permits, approvals and certificates from governmental agencies that regulate their businesses. PHI believes that its subsidiaries have obtained or sought renewal of the material permits, approvals and certificates necessary for their existing operations and that their businesses are conducted in accordance with applicable laws; however, PHI is unable to predict the impact of future regulatory activities of any of these agencies on its business. Changes in or reinterpretations of existing laws or regulations, or the imposition of new laws or regulations, may require PHI's subsidiaries to incur additional expenses or to change the way they conduct their operations.

PHI's business could be adversely affected by the Mirant bankruptcy.

     In 2000, Pepco sold substantially all of its electricity generation assets to Mirant. As part of the sale, Pepco entered into several ongoing contractual arrangements with Mirant and certain of its subsidiaries. On July 14, 2003, Mirant 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. Depending on the outcome of the proceedings, the Mirant bankruptcy could adversely affect PHI's business. See "Relationship with Mirant Corporation," herein.

Pepco may be required to make additional divestiture proceeds gain-sharing payments to customers in the District of Columbia and Maryland.

     Pepco currently is involved in regulatory proceedings in Maryland and the District of Columbia related to the sharing of the net proceeds from the sale of its generation-related assets. The principal issue in the proceedings is whether Pepco should be required to share with customers the excess deferred income taxes and accumulated deferred investment tax credits 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. Depending on the outcome of the proceedings, Pepco could be required to make additional gain-sharing payments to customers and payments to the IRS in the amount of the associated

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accumulated deferred investment tax credits, and Pepco might be unable to use accelerated depreciation on District of Columbia and Maryland allocated or assigned property. See Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters."

The operating results of PHI's power delivery and competitive energy subsidiaries fluctuate on a seasonal basis and can be adversely affected by changes in weather.

     The businesses of PHI's power delivery and competitive energy subsidiaries are seasonal and weather patterns can have a material impact on their operating performance. Demand for electricity is generally greater in the summer months associated with cooling and demand for electricity and gas is generally greater in the winter months associated with heating as compared to other times of the year. Accordingly, PHI's power delivery and competitive energy subsidiaries historically have generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.

The facilities of PHI's subsidiaries may not operate as planned or may require significant maintenance expenditures, which could decrease their revenues or increase their expenses.

     Operation of generation, transmission and distribution facilities involves many risks, including the breakdown or failure of equipment, accidents, labor disputes and performance below expected levels. Older facilities and equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures for additions or upgrades to keep them operating at peak efficiency, to comply with changing environmental requirements, or to provide reliable operations. Natural disasters and weather-related incidents, including tornadoes, hurricanes and snow and ice storms, also can disrupt generation, transmission and distribution delivery systems. Operation of generation, transmission and distribution facilities below expected capacity levels can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance. Furthermore, if PHI's operatin g subsidiaries are unable to perform their contractual obligations for any of these reasons, they may incur penalties or damages.

The transmission facilities of PHI's power delivery subsidiaries are interconnected with the facilities of other transmission facility owners whose actions could have a negative impact on the operations of PHI's subsidiaries.

     The transmission facilities of Pepco, DPL and ACE are directly interconnected with the transmission facilities of contiguous utilities and as such are part of an interstate power transmission grid. FERC has designated a number of regional transmission operators to coordinate the operation of portions of the interstate transmission grid. Each of Pepco, DPL and ACE is a member of PJM, which is the regional transmission operator that coordinates the movement of electricity in all or parts of Delaware, Maryland, New Jersey, Ohio, Pennsylvania, Virginia, West Virginia and the District of Columbia. Pepco, DPL and ACE operate their transmission facilities under the direction and control of PJM. PJM and the other regional transmission operators have established sophisticated systems that are designed to ensure the reliability of the operation of transmission facilities and prevent the operations of one utility from having an adverse impact o n the operations of the other utilities. However, the systems put in

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place by PJM and the other regional transmission operators may not always be adequate to prevent problems at other utilities from causing service interruptions in the transmission facilities of Pepco, DPL or ACE. If any of Pepco, DPL or ACE were to suffer such a service interruption, it could have a negative impact on its and PHI's business.

The cost of compliance with environmental laws is significant and new environmental laws may increase the expenses of PHI and its subsidiaries.

     The operations of PHI's subsidiaries, both regulated and unregulated, are subject to extensive federal, state and local environmental statutes, rules and regulations, relating to air quality, water quality, spill prevention, waste management, natural resources, site remediation, and health and safety. These laws and regulations require PHI's subsidiaries to make capital expenditures and to incur other expenditures to, among other things, meet emissions standards, conduct site remediation and perform environmental monitoring. PHI's subsidiaries also may be required to pay significant remediation costs with respect to third party sites. If PHI's subsidiaries fail to comply with applicable environmental laws and regulations, even if caused by factors beyond their control, such failure could result in the assessment of civil or criminal penalties and liabilities and the need to expend significant sums to come into compliance.

     In addition, PHI's subsidiaries incur costs to obtain and comply with a variety of environmental permits, licenses, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval or if PHI's subsidiaries fail to obtain, maintain or comply with any such approval, operations at affected facilities could be halted or subjected to additional costs.

     New environmental laws and regulations, or new interpretations of existing laws and regulations, could impose more stringent limitations on the operations of PHI's subsidiaries or require them to incur significant additional costs. PHI's current compliance strategy may not successfully address the relevant standards and interpretations of the future.

PHI's competitive energy business is highly competitive.

     The unregulated energy generation, supply and marketing businesses in the mid-Atlantic region are characterized by intense competition at both the wholesale and retail levels. PHI's competitive energy businesses compete with numerous non-utility generators, independent power producers, wholesale power marketers and brokers, and traditional utilities that continue to operate generation assets. This competition generally has the effect of reducing margins and requires a continual focus on controlling costs.

PHI's competitive energy businesses rely on some transmission and distribution assets that they do not own or control to deliver wholesale electricity and to obtain fuel for their generation facilities.

     PHI's competitive energy businesses depend upon transmission facilities owned and operated by others for delivery to customers. The operation of their generation facilities also depends upon coal, natural gas or diesel fuel supplied by others. If electric transmission is disrupted or capacity is inadequate or unavailable, the competitive energy businesses' ability to sell and deliver wholesale power, and therefore to fulfill their contractual obligations, could be adversely affected. Similarly, if the fuel supply to one or more of their generation plants is disrupted and storage or other alternative sources of supply are not available the competitive energy

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businesses' ability to operate their generating facilities could be adversely affected.

Changes in technology may adversely affect PHI's power delivery and competitive energy businesses.

     Research and development activities are ongoing to improve alternative technologies to produce electricity, including fuel cells, microturbines and photovoltaic (solar) cells. It is possible that advances in these or other alternative technologies will reduce the costs of electricity production from these technologies, thereby making the generating facilities of PHI's competitive energy businesses less competitive. In addition, increased conservation efforts and advances in technology could reduce demand for electricity supply and distribution, which could adversely affect PHI's power delivery and competitive energy businesses. Changes in technology also could alter the channels through which retail electric customers buy electricity, which could adversely affect PHI's power delivery businesses.

PHI's risk management procedures may not prevent losses in the operation of its competitive energy businesses.

     The operations of PHI's competitive energy businesses are conducted in accordance with sophisticated risk management systems that are designed to quantify risk. However, actual results sometimes deviate from modeled expectations. In particular, risks in PHI's energy activities are measured and monitored utilizing value-at-risk models to determine the effects of the potential one-day favorable or unfavorable price movement. These estimates are based on historical price volatility and assume a normal distribution of price changes. Consequently, if prices significantly deviate from historical prices, PHI's risk management systems, including assumptions supporting risk limits, may not protect PHI from significant losses. In addition, adverse changes in energy prices may result in economic losses in PHI's earnings and cash flows and reductions in the value of assets on its balance sheet under applicable accounting rules.

The commodity hedging procedures used by PHI's competitive energy businesses may not protect them from significant losses caused by volatile commodity prices.

     To lower the financial exposure related to commodity price fluctuations, PHI's competitive energy businesses routinely enter into contracts to hedge the value of their assets and operations. As part of this strategy, PHI's competitive energy businesses utilize fixed-price, forward, physical purchase and sales contracts, tolling agreements, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges. Conectiv Energy's goal is to hedge 75% of both the expected power output of its generation facilities and the costs of fuel used to operate those facilities. However, the actual level of hedging coverage may vary from these goals. The economic hedge goals are approved by PHI's Corporate Risk Management Committee and may change from time to time based on market conditions. Due to the high heat rate of the Pepco Energy Services power plant generation, Pepco Energy Services infrequently locks in the f orward value of these plants with wholesale contracts. To the extent that PHI's competitive energy businesses have unhedged positions or their hedging procedures do not work as planned, fluctuating commodity prices could result in significant losses.

The expiration of certain hedging arrangements could result in exposure of Conectiv Energy to a higher level of commodity price risk.

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     In order to lower its financial exposure related to commodity price fluctuations, Conectiv Energy entered into an agreement consisting of a series of energy contracts with an international investment banking firm. This agreement is designed to hedge approximately 50% of Conectiv Energy's generation output and approximately 50% of its supply obligations, with the intention of providing Conectiv Energy with a more predictable earnings stream during the term of the agreement. This 35-month agreement consists of two major components: (i) a fixed price energy supply hedge that will be used to reduce Conectiv Energy's financial exposure under its current POLR and SOS supply commitment to DPL which extends through May 2006 and (ii) a generation off-take agreement under which Conectiv Energy will receive a fixed monthly payment from the counterparty, and the counterparty will receive the profit realized from the sale of approximately 50% of the elect ricity generated by Conectiv Energy's plants (excluding the Edge Moor facility).

     This series of energy contracts will terminate in May 2006. As a result, Conectiv Energy will be exposed to a higher level of commodity price risk, unless it were to replace the expiring contracts with new or similar contracts to hedge plant output and any future supply obligations that Conectiv Energy might enter into. Conectiv Energy cannot at this time predict whether or to what extent it will, or will be able to, enter into new hedging contracts that provide commodity price risk protection.

Acts of terrorism could adversely affect PHI's businesses.

     The threat of or actual acts of terrorism may affect the operations of PHI and its subsidiaries in unpredictable ways and may cause changes in the insurance markets, force PHI and its subsidiaries to increase security measures and cause disruptions of fuel supplies and markets. If any of PHI's infrastructure facilities, such as its electric generation, fuel storage, transmission or distribution facilities, were to be a direct target, or an indirect casualty, of an act of terrorism, its operations could be adversely affected. Instability in the financial markets as a result of terrorism also could affect the ability of PHI and its subsidiaries to raise needed capital.

The insurance coverage of PHI and its subsidiaries may not be sufficient to cover all casualty losses that they might incur.

     PHI and its subsidiaries currently have insurance coverage for their facilities and operations in amounts and with deductibles that they consider appropriate. However, there is no assurance that such insurance coverage will be available in the future on commercially reasonable terms. In addition, some risks, such as weather related casualties, may not be insurable. In the case of loss or damage to property, plant or equipment, there is no assurance that the insurance proceeds, if any, received will be sufficient to cover the entire cost of replacement or repair.

PHI and its subsidiaries may be adversely affected by economic conditions.

     Periods of slowed economic activity generally result in decreased demand for power, particularly by industrial and large commercial customers. As a consequence, recessions or other downturns in the economy may result in decreased revenues and cash flows for PHI's power delivery and competitive energy businesses.

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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     PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which as of December 31, 2004 had a book value of approximately $1.2 billion. All of PCI's cross-border energy leases are with tax indifferent parties and were entered into prior to 2004. On February 11, 2005, the Treasury Department and IRS issued a notice informing taxpayers that the IRS intends to challenge the tax benefits claimed by taxpayers with respect to certain of these transactions.

     PHI believes there is a substantial likelihood that the IRS will challenge the tax benefits realized from the interest and depreciation deductions claimed by PCI with respect to these transactions, or the timing of these benefits, for the years 2001 through 2004. The tax benefits claimed by PCI for these years were approximately $175 million. 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.

     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."

PHI and its subsidiaries are dependent on their ability to successfully access capital markets. An inability to access capital may adversely affect their business.

     PHI and its subsidiaries rely on access to both short-term money markets and longer-term capital markets as a source of liquidity and to satisfy their capital requirements not satisfied by the cash flow from their operations. Capital market disruptions, or a downgrade in credit ratings of PHI or its subsidiaries, would increase the cost of borrowing or could adversely affect their ability to access one or more financial markets. Disruptions to the capital markets could include, but are not limited to:

· recession or an economic slowdown;

· the bankruptcy of one or more energy companies;

· significant increases in the prices for oil or other fuel;

· a terrorist attack or threatened attacks; or

· a significant transmission failure.

PHI may be required to, or may elect to, make significant cash contributions to its defined benefit pension plan.

     PHI follows the guidance of SFAS No. 87, "Employers' Accounting for Pensions" in accounting for pension benefits under the Retirement Plan, a non-contributory defined benefit plan. In accordance with these accounting standards, PHI makes assumptions regarding the valuation of benefit obligations and the performance of plan assets. Changes in assumptions such as the use of a different discount rate or expected return on plan assets, affects the calculation of projected benefit obligations, accumulated benefit obligation, reported pension liability on PHI's balance sheet, and reported annual net periodic pension benefit cost on PHI's income statement.

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     Furthermore, as a result of actual pension plan experience being different from expected, the accumulated benefit obligation (ABO) could be greater than the fair value of pension plan assets. If this were to occur, PHI could be required to recognize an additional minimum liability as prescribed by SFAS No. 87. The liability would be recorded as a reduction to common equity through a charge to Other Comprehensive Income (OCI), and would not affect net income for the year. The charge to OCI would be restored through common equity in future periods when the fair value of plan assets exceeded the accumulated benefit obligation. PHI's funding policy is to make cash contributions to the pension plan sufficient for plan assets to exceed the ABO, and avoid the recognition of an additional minimum liability.

     Use of alternative assumptions could also impact the expected future cash funding requirements for the pension plan if PHI's defined benefit plan did not meet the minimum funding requirements of ERISA.

PHI's cash flow, ability to pay dividends and ability to satisfy debt obligations depend on the performance of its operating subsidiaries. PHI's unsecured obligations are effectively subordinated to the liabilities and the outstanding preferred stock of its subsidiaries.

     PHI is a holding company that conducts its operations entirely through its subsidiaries, and all of PHI's consolidated operating assets are held by its subsidiaries. Accordingly, PHI's cash flow, its ability to satisfy its obligations to creditors and its ability to pay dividends on its common stock are dependent upon the earnings of the subsidiaries and the distribution of such earnings to PHI in the form of dividends. The subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts due on any debt or equity securities issued by PHI or to make any funds available for such payment. Because the claims of the creditors and preferred stockholders of PHI's subsidiaries are superior to PHI's entitlement to dividends, the unsecured debt and obligations of PHI are effectively subordinated to all existing and future liabilities of its subsidiaries and to the rights of the holders of preferred stock to receive dividend payments.

Energy companies are subject to adverse publicity, which may render PHI and its subsidiaries vulnerable to negative regulatory and litigation outcomes.

     The energy sector has been among the sectors of the economy that have been the subject of highly publicized allegations of misconduct in recent years. In addition, many utility companies have been publicly criticized for their performance during recent natural disasters and weather related incidents. Adverse publicity of this nature may render legislatures, regulatory authorities, and tribunals less likely to view energy companies such as PHI and its subsidiaries in a favorable light and may cause them to be susceptible to adverse outcomes with respect to decisions by such bodies.

Provisions of the Delaware General Corporation Law and PHI's organizational documents may discourage an acquisition of PHI.

     PHI's organizational documents and the Delaware General Corporation Law both contain provisions that could impede the removal of PHI's directors and discourage a third party from making a proposal to acquire PHI. For example, PHI has a staggered board of directors that is divided into three classes of equal size, with one class elected each year for a term of three years. In addition, as a Delaware corporation, PHI is subject to the business combination law set forth in Section 203 of the Delaware General Corporation Law, which could have the effect of delaying, discouraging or preventing an acquisition of PHI.

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FORWARD LOOKING STATEMENTS

     Some of the statements contained in this Annual Report on Form 10-K are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act 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 indus try's actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements.

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

· Prevailing governmental policies and regulatory actions affecting the energy industry, including 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 our business and profitability;

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· 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 Annual 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 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.

     Pepco Holdings undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. 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

RESULTS OF OPERATIONS

     The results of operations discussion below is for the year ended December 31, 2004 compared to the year ended December 31, 2003. All dollar amounts are in millions.

Operating Revenue

	2004	2003	Change
Regulated T&D Electric Revenue	$  845.4	$  786.8	$ 58.6
Default Supply Revenue	924.5	739.2	185.3
Other Electric Revenue	36.0	22.0	14.0
Total Operating Revenue	$1,805.9	$1,548.0	$257.9

     The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue). Regulated T&D (Transmission & Distribution) Electric Revenue consists of the revenue Pepco receives for delivery of electricity to its customers for which service Pepco is paid regulated rates. Default Supply Revenue (DSR) also known as Standard Offer Service (SOS) consists of revenue Pepco receives from the supply of electricity at regulated rates. 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 col lection fees.

     Regulated T&D Electric Revenue

     Regulated T&D Electric Revenue increased by $58.6 million primarily due to the following: (i) $12.4 million increase due to sales growth of 2.4%, (ii) $10.4 million increase due to favorable weather, and (iii) $39.9 million increase in tax pass-throughs, primarily a county surcharge (offset in Other Taxes) reduced by (iv) $3.3 million decrease related to PJM network transmission revenue. Delivery sales were approximately 26,902,000 MwH, compared to approximately 25,994,000 MwH for the comparable period in 2003. Cooling degree days increased by 19.5% and heating degree days decreased by 6.5% for the year ended December 31, 2004 as compared to the same period in 2003.

     Default Supply Revenue

     Default Supply Revenue increased by $185.3 million primarily due to higher retail energy rates, the result of an effective rate increase in Maryland beginning in July 2004 and lower customer migration, principally in DC.

     For the twelve months ended December 31, 2004, Pepco's Maryland customers served by an alternate supplier represented 29% of Pepco's total

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Maryland load, and Pepco's DC customers served by an alternate supplier represented 32% of Pepco's total DC load. For the twelve months ended December 31, 2003, Pepco's Maryland customers served by an alternate supplier represented 30% of Pepco's total Maryland load, and Pepco's DC customers served by an alternate supplier represented 48% of Pepco's total DC load.

     Default Supply sales were approximately 18,819,000 MwH for the twelve months ended December 31, 2004, compared to approximately 16,199,000 MwH for the comparable period in 2003.

     Other Electric Revenue

     Other Electric Revenue increased by $14.0 million primarily due to increased customer requested work for the year ended December 31, 2004 (offset in Other Operation and Maintenance).

Operating Expenses

     Fuel and Purchased Energy

     Fuel and Purchased Energy increased by $215.2 million to $899.3 million in 2004, from $684.1 million in 2003. The increase was primarily due to the following: (i) $180.6 million higher energy costs, the result of the new Default Supply rates for Maryland beginning in July 2004, and less customer migration, principally in DC, (ii) $74.6 million higher costs due to an increased rate change from the TPA Settlement with Mirant, effective October 2003, and (iii) $4.0 million higher PJM network transmission costs. These increases were partially offset by (i) $29.5 million reduction in the General Procurement Credit (GPC) which resulted from the lower Default Supply margin, and (ii) $14.5 million reserve recorded in September 2003 to reflect a potential exposure related to a pre-petition receivable from Mirant Corp. for which Pepco filed a creditor's claim in the bankruptcy proceedings. See the Regulatory and Other Matters - Relationship with Mirant section herein for additional information related to Mirant.

     Other Operation and Maintenance

     Other Operation and Maintenance increased by $33.8 million to $272.3 million in 2004, from $238.5 million in 2003. The increase was primarily due to (i) $12.1 million of customer requested work (offset in Other Electric Revenue), (ii) $9.7 million higher electric system operation and maintenance costs, (iii) $4.8 million for severance costs, (iv) $2.8 million for right of way maintenance, (v)$2.7 million for the uncollectible and claims reserve, (vi) $3.3 million for Sarbanes-Oxley external compliance costs, (vii) $2.5 million for legal and commission fees, (viii) $2.5 million for deferred costs and inventory adjustments, (ix) $2.5 million bad debt expense, offset by (x) $7.1 million for storm costs primarily related to one time charges related to Hurricane Isabel in September 2003 and (xi) $2.0 million decrease in other costs.

     Depreciation and Amortization

     Depreciation and Amortization expenses decreased by $3.5 million to $166.3 million in 2004 from $169.8 million in 2003. The decrease is primarily due to a $4.1 million decrease in energy use management (EUM) amortization.

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     Other Taxes

     Other Taxes increased by $42.2 million to $248.7 million in 2004, from $206.5 million in 2003. The increase was primarily due to (i) pass-throughs of $33.9 million higher county surcharge and $3.6 million higher gross receipts/delivery taxes (offset in Regulated T&D Electric Revenue), (ii) $1.4 million higher Public Service Commission fees, (iii) $1.1 million county Right-of-Way fee adjustment in 2003, and (iv) $.8 million higher use tax.

     Gain on Sale of Assets

     GainonSale of Assets increased by $6.9 million primarily resulting from $6.6 million for the sale of land in the first quarter of 2004.

Other Income (Expenses)

     Other Expenses increased by $2.1 million to a net expense of $72.9 million in 2004 from a net expense of $70.8 million in 2003. This was primarily due to $2.5 million lower interest income.

Preferred Stock Dividend Requirements

     Preferred Stock Dividend Requirements decreased by $6.9 million from 2003. Of this decrease $4.6 million resulted from lower dividends in 2004 due to the redemption of the Trust Originated Preferred Securities in 2003 and $1.6 million was attributable to SFAS No. 150, which requires that dividends on Mandatorily Redeemable Serial Preferred Stock declared subsequent to July 1, 2003, be recorded as interest expense.

Income Tax Expense

     Pepco's effective tax rate for 2004 was 37% 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 tax credits and changes in estimates related to tax liabilities of prior tax years subject to audit (which was the primary reason for the lower effective tax rate as compared to 2003).

     Pepco's effective tax rate for 2003 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) and the flow-through of certain book tax depreciation differences.

     The results of operations discussion below is for the year ended December 31, 2003 compared to the year ended December 31, 2002.

Lack Of Comparability Of Operating Results With Prior Years

     Pepco's results of operations for the year ended December 31, 2003 include only its operations. However, Pepco's results of operations for the year ended 2002, as previously reported by Pepco, include Pepco's operations consolidated with its pre-merger subsidiaries' (Potomac Capital Investment Corporation (PCI) and Pepco Energy Services) operations through July 2002. Accordingly, the results of operations for 2003 and 2002 are not comparable. In connection with Pepco's acquisition of Conectiv in August 2002, PCI and Pepco Energy Services were transferred to PHI.

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Operating Revenue

     Pepco's consolidated operating revenue decreased by $440.0 million to $1,548.0 million in 2003 from $1,988.0 million in 2002. This decrease was primarily due to a decrease in operating revenue recognized of $401.0 million at Pepco Energy Services and a decrease of $53.1 million at PCI. These decreases were due to the fact that Pepco Energy Services and PCI's operating results were not recorded by Pepco in 2003 because subsequent to July 2002 their ownership was transferred to PHI. These decreases were partially offset by an increase of $14.1 million in Pepco's operating revenue due to the following:

     Regulated T&D Electric Revenue increased by $18.5 million in 2003. This increase results from a $19.2 million increase from a fuel tax pass-through, partially offset by a $.7 million decrease in Regulated T&D Electric Revenue. The $.7 million decrease resulted from a .6% decrease in delivered kilowatt-hour sales.

     DSR increased by $4.2 million in 2003 due to colder winter weather as heating degree days increased by 12.2% offset by a 30.2% decrease in cooling degree days.

     Pepco's retail access to a competitive market for generation services was made available to all Maryland customers on July 1, 2000 and to D.C. customers on January 1, 2001. At December 31, 2003, 14% of Pepco's Maryland customers and 11% of its D.C. customers have chosen alternate suppliers. These customers accounted for 912 megawatts of load in Maryland (of Pepco's total load of 3,439) and 970 megawatts of load in D.C. (of Pepco's total load of 2,269). At December 31, 2002, 16% of Pepco's Maryland customers and 13% of its D.C. customers have chosen alternate suppliers. These customers accounted for 1,175 megawatts of load in Maryland (of Pepco's total load of 3,369) and 1,140 megawatts of load in D.C. (of Pepco's total load of 2,326).

     Other Electric Revenue decreased $8.6 million primarily due to lower capacity (megawatts) available to sell, lower capacity market rates and restructuring in the PJM market.

Operating Expenses

     Fuel and Purchased Energy

     Pepco's consolidated fuel and purchased energy decreased by $310.6 million to $684.1 million in 2003 from $994.7 million in 2002. This decrease was primarily due to a decrease in fuel and purchases energy recognized of $340.3 million at Pepco Energy Services due to the fact that Pepco Energy Services operating results were not recorded by Pepco in 2003 because subsequent to July 2002 its ownership was transferred to PHI. This decrease was partially offset by an increase of $29.7 million at Pepco primarily due to the recording of a $14.5 million reserve to reflect a potential exposure related to a pre-petition receivable from Mirant Corp., for which Pepco filed a creditor's claim in bankruptcy proceedings and from $15.3 million higher SOS costs.

     Other Operation and Maintenance

     Pepco's consolidated other operation and maintenance decreased by $78.4 million to $238.5 million in 2003 from $316.9 million in 2002. This decrease was primarily due to a decrease in other operation and maintenance expense recognized of $57.9 million at Pepco Energy Services and a decrease of $24.6 million at PCI. These decreases were due to the fact that Pepco Energy

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Services and PCI's operating results were not recorded by Pepco in 2003 because subsequent to July 2002 their ownership was transferred to PHI. These decreases were partially offset by an increase of $4.1 million in Pepco's other operation and maintenance expense due to storm restoration expenses incurred.

     Depreciation and Amortization

     Pepco's consolidated depreciation and amortization increased by $16.5 million to $169.8 million in 2003 from $153.3 million in 2002. This increase was primarily due to an increase at Pepco of $11.6 related to software amortization during the year, partially offset by a decrease of $1.7 million at Pepco Energy Services and $3.2 million at PCI due to the fact that Pepco Energy Services and PCI's operating results were not recorded by Pepco in 2003 because subsequent to July 2002 their ownership was transferred to PHI.

     Other Taxes

     Pepco's consolidated other taxes increased by $8.3 million to $206.5 million in 2003, from $198.2 million for the corresponding period in 2002. This increase was due to higher fuel taxes over the period.

Other Income (Expenses)

     Pepco's consolidated other expenses decreased by $25.5 million to $70.8 million in 2003 from $96.3 million for the corresponding period in 2002. This decrease was primarily due to a decrease in operating revenue recognized of $19.8 at PCI, partially offset by a $3.1 million increase at Pepco. The decrease at PCI was due to the fact that its operating results were not recorded by Pepco in 2003 because subsequent to July 2002 its ownership was transferred to PHI.

Income Tax Expense

     Pepco's effective tax rate in 2003 was 40% as compared to the federal statutory rate of 35%. The major reasons for this difference are state income taxes (net of federal benefit) and the flow-through of certain book tax depreciation differences. In 2002, the effective rate was 37% as compared to the federal statutory rate of 35%. The major reasons for this difference are state income taxes (net of federal benefit) and the flow-through of certain book tax depreciation differences, partially offset by the inclusion of the tax benefits of Pepco's pre-merger subsidiaries through July 2002.

CAPITAL RESOURCES AND LIQUIDITY

General

     Financing Activities

     Pepco issued $275 million of secured senior notes with maturities of 10 and 30 years. Proceeds of $272.8 million were used to redeem higher interest rate securities of $210 million and to repay short-term debt of $56.6 million. Pepco borrowed $100 million under a bank loan due in 2006. Proceeds were used to redeem Mandatorily Redeemable Preferred Stock of $42.5 million and to repay short-term debt.

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     Working Capital

     At December 31, 2004, Pepco's current assets on a consolidated basis totaled $354.4 million and its current liabilities totaled $416.1 million. At December 31, 2003, PHI's current assets totaled $347.2 million and its current liabilities totaled $418.6 million.

     Pepco's working capital deficit results in large part from the fact that, in the normal course of business, it acquires energy supplies for its customers before the supplies are delivered to, 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.

Summary of Cash Flows

     Pepco's cash flows for 2004, 2003, and 2002 are summarized below.

	Cash Provided / (Used)
	2004	2003	2002
	(Dollars in Millions)
Operating Activities	$ 274.5	$ 325.9	$ 471.8
Investing Activities	(181.7)	(197.5)	(324.3)
Financing Activities	(98.1)	(139.8)	(644.8)
Net change in cash and cash equivalents	$  (5.3)	$ (11.4)	$(497.3)

     Operating Activities

     Cash flows from operating activities are summarized below for 2004, 2003, and 2002.

	Cash Provided / (Used)
	2004	2003	2002
	(Dollars in Millions)
Net Income	$ 96.6	$104.6	$139.1
Non-cash adjustments to net income	194.0	249.4	296.2
Changes in working capital	(16.1)	(28.1)	36.5
Net cash provided by operating activities	$274.5	$325.9	$471.8

     Net cash flows provided by operating activities decreased by $51.4 million to $274.5 million for 2004 from $325.9 million for 2003. The $51.4 million decrease was mainly due to proceeds received on a note receivable from PCI in 2003.

     In 2003 cash flows from operating activities decreased by $145.9 million to $325.9 million from $471.8 million for 2002. The $145.9 million decrease was primarily due to a federal income tax refund in 2002 and less activity in 2003 due to the transfer of PCI as a subsidiary of Pepco to a subsidiary of Pepco Holdings, Inc. following the acquisition of Conectiv by Pepco in 2002.

     Investing Activities

     A summary of the significant items included in cash flows from investing activities during 2004, 2003, and 2002 are summarized below.

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	Cash Provided / (Used)
	2004	2003	2002
	(Dollars in Millions)
Capital expenditures	$(204.1)	$(197.5)	$(194.7)
Cash proceeds from (purchase of)   other investments	22.4	-	(13.2)
Purchase of leveraged leases	-	-	(111.6)
All other investing cash flows, net	-	-	(4.8)
Net cash used by investing activities	$(181.7)	$(197.5)	$(324.3)

     The change in investing activities in 2004 from 2003 mainly results from $22.4 million in proceeds received from the sale of two substations.

     The $126.8 million decrease in investing cash flows in 2003 compared to 2002 primarily results from the acquisition of leveraged leases in 2002 by PCI.

     Financing Activities

     Cash flows from financing activities result from issuing, repurchasing, and redeeming debt and equity securities, and paying dividends, and are summarized below for 2004, 2003, and 2002.

	Cash Provided / (Used)
	2004	2003	2002
	(Dollars in Millions)
Dividends on common and preferred stock	$(103.4)	$ (68.2)	$(499.9)
Preferred securities redemptions	(53.3)	(127.5)	(2.0)
Long-term debt, net	165.0	(5.7)	(95.3)
Short-term debt, net	(93.5)	67.5	(43.2)
All other financing cash flows, net	(12.9)	(5.9)	(4.4)
Net cash used by financing activities	$ (98.1)	$(139.8)	$(644.8)

     In December 2004, Pepco issued $100 million in long-term debt via a term loan due December 1, 2006. Proceeds were used to redeem all ($42.5 million) of Pepco's mandatorily redeemable $3.40 series preferred stock and to repay short-term debt. Also in 2004, Pepco issued $275 million of secured senior notes.

     In 2003 Pepco redeemed its mandatorily redeemable trust preferred securities totaling $125 million.

     Dividends on common and preferred stock were $103.4 million in 2004, $68.2 million in 2003, and $499.9 million in 2002. The 2002 dividend was due to the August 1, 2002 acquisition of Conectiv by Pepco.

Capital Requirements

     Construction Expenditures

     Pepco's construction expenditures for the year ended December 31, 2004 totaled $204.1 million. For the five-year period 2005 through 2009, Pepco's total construction expenditures are projected to be approximately $750.0 million.

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     Dividends

     Under PUHCA, PHI is prohibited, without SEC approval, from paying dividends on its common stock from capital or unearned surplus. PHI generates no operating income of its own. Accordingly, its ability to pay dividends to its shareholders depends on dividends received from its subsidiaries.

     Pepco's articles of incorporation contain provisions restricting the amount of dividends that can be paid on common stock when preferred stock is outstanding if the applicable company's capitalization ratio is less than 25%. For this purpose, the capitalization ratio is equal to (i) common stock capital plus surplus, divided by (ii) total capital (including long-term debt) plus surplus.

     Pension Funding

     Pepco Holdings has a noncontributory retirement plan (the Retirement Plan) that covers substantially all employees of Pepco, Conectiv and certain employees of other Pepco Holdings' subsidiaries. Following the consummation of the acquisition of Conectiv by Pepco on August 1, 2002, the Pepco General Retirement Plan and the Conectiv Retirement Plan were merged into the Retirement Plan on December 31, 2002. The provisions and benefits of the merged Retirement Plan applicable to Pepco employees are identical to those in the original Pepco plan and the provisions and benefits applicable to Conectiv employees are identical to those in the original Conectiv plan.

     As of the 2004 valuation, the Retirement Plan satisfied the minimum funding requirements of the Employment Retirement Income Security Act of 1974 (ERISA) without requiring any additional funding. However, PHI's funding policy with regard to the Retirement Plan is to maintain a funding level in excess of 100% of its accumulated benefit obligation. In 2004 and 2003, PHI made discretionary tax-deductible cash contributions to the Retirement Plan in accordance with its funding policy.

     In 2004, the accumulated benefit obligation (ABO) for the Retirement Plan increased over 2003, due to the accrual of an additional year of service for participants and a decrease in the discount rate used to value the accumulated benefit obligation. The change in the discount rate reflected the continued decline in interest rates in 2004. The Retirement Plan assets achieved returns in 2004 in excess of the levels assumed in the valuation. As a result of the combination of these factors, in December 2004 PHI contributed $10 million (all of which was funded by Pepco) to the Retirement Plan. The contribution was made to ensure that under reasonable assumptions, the funding level at year end would be in excess of 100% of the accrued benefit obligation. In 2003, PHI contributed a total of $50 million (of which $30 million was funded by Pepco and $20 million was funded by ACE) to the Retirement Plan. Assuming no changes to the current pension p lan assumptions, PHI projects no funding will be required under ERISA in 2005; however, PHI may elect to make a discretionary tax-deductible contribution, if required to maintain its assets in excess of its ABO.

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     Contractual Obligations And Commercial Commitments

     Summary information about Pepco's consolidated contractual obligations and commercial commitments at December 31, 2004, is as follows:

	Contractual Maturity
Obligation	Total	Less than 1 Year	1-3   Years	4-5   Years	After  5 Years
	(Dollars in Millions)
Short-term debt	$   14.0	$ 14.0	$      -	$    -	$      -
Long-term debt	1,301.8	100.0	310.0	178.0	713.8
Interest payments on debt	712.5	73.0	128.3	87.5	423.7
Capital leases	229.7	15.7	31.1	30.6	152.3
Purchase power contracts (a)	1,114.3	154.9	799.5	159.9	-
Total	$3,372.3	$357.6	$1,268.9	$456.0	$1,289.8

(a) Excludes the PPA Related Obligations that are part of the back-to-back agreement that was entered into with Mirant. Refer to the "Relationship with Mirant" section herein for additional information.

Sources Of Capital

     Pepco's sources to meet its long-term funding needs, such as capital expenditures, and its short-term funding needs, such as working capital and the temporary funding of long-term funding needs, include internally generated funds, security issuances and bank financing under new or existing facilities. Pepco's ability to generate funds from its operations and to access capital and credit markets is subject to risks and uncertainties. See "Risk Factors" for a discussion of important factors that may impact these sources of capital.

     Short-Term Funding Sources

     Pepco has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements.

     Pepco maintains an ongoing commercial paper program of up to $300 million. The commercial paper notes can be issued with maturities up to 270 days from the date of issue.

     In July 2004, Pepco Holdings, Pepco, DPL and ACE entered into a five-year credit agreement with an aggregate borrowing limit of $650 million. This agreement replaced a $550 million 364-day credit agreement that was entered into on July 29, 2003. The respective companies also are parties to a three-year credit agreement that was entered into in July 2003 and terminates in July 2006 with an aggregate borrowing limit of $550 million. Pepco Holdings' credit limit under these facilities is $700 million, and the credit limit of each of Pepco, DPL and ACE under these facilities is the lower of $300 million and the maximum amount of short-term debt authorized by the appropriate state commission, except that the aggregate amount of credit utilized by Pepco, DPL and ACE at any given time under these facilities may not exceed $500 million. Funds borrowed under these facilities are available for general corporate purposes. Either credit facility also can be used as credit support for the commercial paper programs of the respective companies.

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The three-year and five-year credit agreements contain customary financial and other covenants that, if not satisfied, could result in the acceleration of repayment obligations under the agreements or restrict the ability of the companies to borrow under the agreements. Among these covenants is 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 agreements. As of December 31, 2004, the applicable ratios for Pepco Holdings, Pepco, DPL and ACE were 59.0%, 58.5%, 52.1% and 50.2%, respectively. The credit agreements also contain a number of customary events of default that could result in the acceleration of repayment obligations under the agreements, including (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 agreements) of Pepco Holdings or the failure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE.

     In December 2004, PHI entered into a $50 million term loan due December 13, 2005 with a bank. The loan is variable rate, based on LIBOR. PHI has the option to select interest periods based on one, two, three or six month LIBOR rates. The covenants in the agreement are substantially consistent with those found in the three-year and five-year credit agreements. Proceeds from the loan were used to pay down commercial paper.

     Long-Term Funding Sources

     The sources of long-term funding for Pepco are the issuance of debt and equity securities and borrowing under long-term credit agreements. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures and new investments, and to refund or refinance existing securities.

PUHCA Restrictions

     An SEC Financing Order dated July 31, 2002 (the "Financing Order"), requires that, in order to issue debt or equity securities, including commercial paper, Pepco must maintain a ratio of common stock equity to total capitalization (consisting of common stock, preferred stock, if any, long-term debt and short-term debt) of at least 30 percent. At December 31, 2004 and 2003, Pepco's common equity ratio was 42.8 percent and 43.4 percent, respectively. The Financing Order also requires that all rated securities issued by Pepco be rated "investment grade" by at least one nationally recognized rating agency. Accordingly, if Pepco's common equity ratio were less than 30 percent or if no nationally recognized rating agency rated a security investment grade, Pepco could not issue the security without first obtaining from the SEC an amendment to the Financing Order.

     If an amendment to the Financing Order is required to enable Pepco to effect a financing, there is no certainty that such an amendment could be obtained, as to the terms and conditions on which an amendment could be obtained or as to the timing of SEC action. The failure to obtain timely relief from the SEC, in such circumstances, could have a material adverse effect on the financial condition of Pepco.

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Other Liquidity Considerations

     For a discussion of the potential impact of the Mirant bankruptcy on liquidity, see "Relationship with Mirant Corporation" section that follows.

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., pursuant to an Asset Purchase and Sale Agreement. As part of the Asset Purchase and Sale Agreement, Pepco entered into several ongoing contractual arrangements with Mirant 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).

     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 currently 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 have arisen or 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 standard offer service obligations in Maryland through June 2004 and its standard offer service 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 that 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 current plan of reorganization filed by the Mirant entities with the Bankruptcy Court, certain Mirant entities other than Mirant Corporation would

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pay significantly higher portions 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 an agreement with Panda, entered into in 1991, Pepco is obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (the Panda PPA). 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 Oblig ations).

     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 which 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 this uncertainty, Pepco, in the third quarter of 2003, expen sed $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 amou nt ultimately recovered could be higher or lower.

     Mirant's Attempt to Reject the PPA-Related Obligations

     On August 28, 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

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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). On August 4, 2004, the Court of Appeals remanded the case to the District Court saying that the District Court has 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 judgment 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 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, 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.

     As more fully discussed below, Mirant had been making regular periodic payments in respect of the PPA-Related Obligations. On December 9, 2004, Mirant filed a notice with the Bankruptcy Court that it was suspending payments to Pepco in respect of the PPA-Related Obligations. On December 13, 2004, Mirant failed to make a payment of approximately $17.9 million due to Pepco for the period November 1, 2004 to November 30, 2004. Mirant failed to make that payment. On December 23, 2004, Pepco received a payment of approximately $6.8 million from Mirant, which according to Mirant represented the market value of the power for which payment was due on December 13. Mirant has informed Pepco that it intends to continue to pay the market value, but not the above-market portion, of the power purchased under the PPA-Related Obligations. Pepco disagrees with Mirant's assertion that it need only pay the market value and believes that the amount repr esenting the market value calculated by Mirant is insufficient.

     On January 21, 2005, Mirant made a approximately $21.1 million, which, according to Mirant, includes the payment for the FirstEnergy PPA for December 2004 and "includes the December 2004 TPA revenue in the amount of $29,093,173.43, the TPA costs in the amount of $37,865,924.10, and an allocated share of [FirstEnergy's] PPA bill credits/charges in the amount of $5,490,164.79." Pepco disputes Mirant's contention that the amount paid reflects the full amount due Pepco under these agreements for the applicable periods.

     As of March 1, 2005, Mirant has withheld payment of approximately $34.8 million due to Pepco under 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. On March 1, 2005 (as amended by order dated March 7, 2005), the District Court granted Pepco's motion to withdraw jurisdiction over the Asset Purchase and Sale Agreement rejection proceedings from the Bankruptcy Court. In addition, the District Court ordered Mirant to pay on March 18, 2005, all past-due unpaid amounts under the PPA-Related Obligations. Mirant has filed a motion for reconsideration and a stay of the March 1, 2005 order.

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     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 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 $133.2 million as of March 1, 2005 (assuming Mirant continues to withhold unpaid amounts of approximately $34.8 million as of March 1, 2005.

     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 March 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 March 1, 2005, at the rates provided in the PPA (with an average price per kilowatt hour of approximately 6.0 cents) and resold the capacity and energy at market rates projected, given the characteristics of the FirstEnergy PPA, to be approximately 5.0 cents per kilowatt hour, Pepco estimates that it would cost approximately $31 million for the remainder of 2005, the final year of the FirstEnergy PPA.

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· If Pepco were required to purchase capacity and energy from Panda commencing as of March 1, 2005, at the rates provided in the PPA (with an average price per kilowatt hour of approximately 16.9 cents), and resold the capacity and energy at market rates projected, given the characteristics of the Panda PPA, to be approximately 7.4 cents per kilowatt hour, Pepco estimates that it would cost approximately $29 million for the remainder of 2005, approximately $34 million in 2006 and 2007, and approximately $34 million to $49 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.

     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 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 distribution rates. If Pe pco'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. However, the accounting treatment of such a loss depends on a number of legal and regulatory factors, and is not determinable at this time.

     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.

     On March 15, 2004, Mirant filed a complaint with the Bankruptcy Court seeking a declaratory judgment that the facility and capacity credit

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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.

Rate Proceedings

     In compliance with the settlement approved by the MPSC in connection with the merger of Pepco and Conectiv, on December 4, 2003, Pepco submitted testimony and supporting schedules to review and reset if necessary its electricity distribution rates in Maryland to be effective July 1, 2004, when the then-current distribution rate freeze/caps ended. Pepco's filing demonstrated that it was in an under-earning situation. However the merger settlement provided that Pepco's distribution rates after July 1, 2004 could only remain the same or be decreased. With limited exceptions, Pepco cannot increase its distribution rates until January 1, 2007. In an order dated July 6, 2004 the MPSC affirmed the Hearing Examiner's recommendation that no rate decrease was warranted at that time.

     On July 3, 2004, Pepco filed a distribution rate review case with the DCPSC as required by the terms of the Pepco-Conectiv merger settlement approved by the DCPSC. This case will determine whether Pepco's distribution rates will be decreased. In accordance with the terms of the merger settlement, Pepco's distribution rates cannot be increased as a result of the case. On November 24, 2004, the DCPSC issued an order that designated the issues to be considered in the case and set the hearing schedule. On December 17, 2004, Pepco filed supplemental direct testimony addressing the DCPSC-designated issues. Pepco's filings indicate that no rate decrease is warranted. On March 4, 2005, the DCPSC issued an order granting a joint motion filed on March 3, 2005, on behalf of Pepco and several other parties in the case to suspend the procedural schedule to allow the parties to focus on completing settlement discussions. In the joint motion, the movin g parties informed the DCPSC that they had agreed in principle to settlement provisions that would resolve all issues in the proceeding and that a settlement agreement could be filed in the near future.

Divestiture Cases

     District of Columbia

     Final briefs on Pepco's District of Columbia divestiture proceeds sharing application were filed on July 31, 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. 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. On March 4, 2003, the Internal Revenue Service (IRS) issued a notice of proposed rulemaking (NOPR) that is relevant to that principal issue. Comments on the NOPR were filed by several parties on June 2, 2003, and the IRS held a public hearing on June 25, 2003. As a result of the NOPR,

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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 then 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.

     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 ADITC balance, 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 December 31, 2004, the District of Columbia jurisdictional transmission and distribution-related ADITC balance was approximately $6.0 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 D.C. 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. Reply briefs were filed in May 2002. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that was raised in the D.C. case. As of December 31, 2004, 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, and the generation-related ADITC. If such sharing were to

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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 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 operative. As of December 31, 2004, the Maryland retail jurisdictional transmission and distribution-related ADITC balance was approximately $10.7 million. The Hearing Examiner decided all other issues in favor of Pepco, except that only one-half of the severance payments that Pepco included in its calculation of corporate reorga nization 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 4, 2003 IRS NOPR.

     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 a dverse effect on 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.

SOS and Default Service Proceedings

     District of Columbia

     In February 2003, the DCPSC opened a new proceeding to consider issues relating to (a) the establishment of terms and conditions for providing standard offer service (SOS) in the District of Columbia after Pepco's obligation to provide SOS terminated on February 7, 2005, and (b) the selection of a new SOS provider.

     In December 2003, the DCPSC issued an order that set forth the terms and conditions for the selection of a new SOS provider(s) and the provision of SOS by Pepco on a contingency basis. In December 2003, the DCPSC also issued an order adopting terms and conditions that would apply if Pepco continued as the SOS provider after February 7, 2005. In March 2004, the DCPSC issued an order adopting the wholesale SOS model, i.e., Pepco would continue to be the SOS provider in the District of Columbia after February 7, 2005. This March 2004 order, as amended by a DCPSC order issued in July 2004, extends Pepco's obligation to provide default electricity supply at market rates for up to an additional 76 months for small commercial and residential customers, and for an additional 28 months for large commercial customers.

     In August 2004, the DCPSC issued an order adopting administrative charges for residential, small and large commercial DC SOS customers that are

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intended to allow Pepco to recover the administrative costs incurred to provide the SOS supply. The approved administrative charges include an average margin for Pepco of approximately $0.00248 per kilowatt hour, calculated based on total sales to residential, small and large commercial DC SOS customers over the twelve months ended December 31, 2003. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of DC SOS customers from each customer class and the load taken by such customers over the time period. The administrative charges went into effect for Pepco's DC SOS sales on February 8, 2005. Pepco completed the first competitive procurement process for DC SOS at the end of October and filed the proposed new SOS rates with the DCPSC on November 3, 2004.

     The TPA with Mirant under which Pepco obtained the fixed-rate DC 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 DC 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 DC SOS rates charged to customers during the period from January 23 through January 31, 2005. In addition, because the new DC 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 DC SOS contracts and the DC SOS rates charged to customers for the period from February 1 to February 7, 2005. The total amount of the diff erence is estimated to be approximately $8.7 million. This difference, however, will be included in the calculation of the Generation Procurement Credit (GPC) for DC 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 recovery 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.

     Maryland

     Under a settlement approved by the MPSC in April 2003 addressing SOS service in Maryland following the expiration of Pepco's fixed-rate default supply obligations in July 2004, Pepco is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customers through May 2006, and to large commercial customers through May 2005. In accordance with the settlement, Pepco purchases the power supply required to satisfy its market rate default supply obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved by the MPSC. Pepco is entitled to recover from its default supply customers the cost of the default supply plus an average margin of $0.002 per kilowatt hour, calculated based on total sales to residential, small and large commercial Maryland SOS customers over the twelve months ended December 31, 200 3. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of Maryland SOS customers from each customer class and the load taken by such customers over the time period.

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General Litigation

     Asbestos

     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, plaintiffs argue 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

     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 August 2001, Pepco entered into a consent decree for de minimis parties with EPA to resolve its liability at this site. Under the terms of the consent decree, which was approved by the U.S. District Court for the District of Maryland on March 31, 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

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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 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, 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 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. On May 12, 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. On October 2, 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 December 31, 2004, Pepco had accrued $1.7 million to meet its liability for a site remedy. 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.

     On April 7, 2000, approximately 139,000 gallons of oil leaked from a pipeline at a generating facility that was owned by Pepco at Chalk Point generating facility in Aquasco, Maryland. The pipeline was operated by Support Terminals Services Operating Partnership LP (ST Services), an unaffiliated pipeline management company. The oil spread from Swanson Creek to the Patuxent River and several of its tributaries. The area affected covers portions of 17 miles of shoreline along the Patuxent River and approximately 45 acres of marshland adjacent to the Chalk Point property.

     In December 2000, the Department of Transportation, Office of Pipeline Safety, Research and Special Programs Administration (OPS) issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (NOPV). The NOPV alleged various deficiencies in compliance with regulations related to spill reporting, operations and maintenance of the pipeline and record keeping, none of which relate to the cause of the spill. The NOPV was issued to both Pepco and ST Services and proposed a civil penalty in the amount of $674,000. On June 2, 2004, the OPS issued a Final Order regarding the NOPV in this matter. The Final Order assessed a total fine of $330,250, with $256,250 of that amount assessed jointly against Pepco and ST Services and the remaining $74,000 assessed solely against ST Services. ST Services subsequently filed a Petition for Reconsideration. All penalties were stayed pending the outcome of the Petition for Rec onsideration. On February 9, 2005, OPS issued a Decision on the Petition for Reconsideration that affirmed the Final Order. Pepco's share of the $330,250 penalty assessed pursuant to the Final Order amounts to $128,125.

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CRITICAL ACCOUNTING POLICIES

General

     The SEC has defined a company's most critical accounting policies as the ones that are most important to the portrayal of its financial condition and results of operations, and which require the Company to make its most difficult and subjective judgments, often as a result of the need to make estimates of matters that are inherently uncertain. Critical estimates represent those estimates and assumptions that may be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and that have a material impact on financial condition or operating performance.

Accounting Policy Choices

     Pepco's management believes that based on the nature of the businesses in which its subsidiaries are primarily engaged, Pepco Holdings has very little choice regarding many of the accounting policies it utilizes. In that regard, the most significant portion of Pepco Holdings' business consists of its regulated utility operations, which are subject to the provisions of Statement of Financial Accounting Standards (SFAS) No. 71 "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 does allow regulated entities, in appropriate circumstances, to establish regulatory assets and regulatory liabilities and to defer the income statement impact of certain costs that are expected to be recovered in future rates. However, management believes that in the areas that Pepco is afforded accounting policy choices, its selection from among the alternatives available generally would not have a material impact on the Company's financial con dition or results of operations.

     Use of Estimates

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America, such as Statement of Position 94-6 "Disclosure of Certain Significant Risks and Uncertainties," requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes.

     Examples of significant estimates used by Pepco Holdings include the assessment of contingencies and the need/amount for reserves of future receipts from Mirant (refer to the "Relationship with Mirant" section, herein), the calculation of future cash flows and fair value amounts for use in goodwill and asset impairment evaluations, fair value calculations (based on estimating market pricing) associated with derivative instruments, pension and other post-retirement benefits assumptions, unbilled revenue calculations, and judgment involved with assessing the probability of recovery of regulatory assets. Additionally, Pepco is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of our business. We record an estimated liability for these proceedings and claims based upon the probable and reasonably estimatable criteria contained in SFAS No. 5 "Accounting for Contingencies." Although Pepco believes tha t its estimates and assumptions are reasonable, they are based upon information presently available. Actual results may differ significantly from these estimates.

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     Long-Lived Assets Impairment Evaluation

     Pepco believes that the estimates involved in its long-lived asset impairment evaluation process represent "Critical Accounting Estimates" because they (i) are highly susceptible to change from period to period because management is required to make assumptions and judgments about undiscounted and discounted future cash flows and fair values, which are inherently uncertain, (ii) actual results could vary from those used in Pepco estimates and the impact of such variations could be material, and (iii) the impact that recognizing an impairment would have on Pepco's assets as well as the net loss related to an impairment charge could be material.

     In accordance with the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," an impairment loss shall only be recognized if the carrying amount of an asset is not recoverable and the carrying amount exceeds its fair value. The asset is deemed to not be recoverable when its carrying amount exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. In order to estimate an asset's future cash flows, Pepco considers historical cash flows. Pepco uses its best estimates in making these evaluations and considers various factors, including forward price curves for energy, fuel costs, legislative initiatives, and operating costs.

     Pension and Other Post-retirement Benefit Plans

     Pepco believes that the estimates involved in reporting the costs of providing pension and other post-retirement benefits represent "Critical Accounting Estimates" because (i) they are based on an actuarial calculation that includes a number of assumptions which are subjective in nature, (ii) they are dependent on numerous factors resulting from actual plan experience and assumptions of future experience, and (iii) changes in assumptions could impact Pepco's expected future cash funding requirements for the plans and would have an impact on the projected benefit obligations, the reported pension and other post-retirement benefit liability on the balance sheet, and the reported annual net periodic pension and other post-retirement benefit cost on the income statement. In terms of quantifying the anticipated impact of a change in assumptions, PHI estimates that a .25% change in the discount rate used to value the benefit obligations co uld result in a $5 million impact on its consolidated balance sheets and income statements. Additionally, PHI estimates that a .25% change in the expected return on plan assets could result in a $4 million impact on the consolidated balance sheets and income statements and a .25% change in the assumed healthcare cost trend rate could result in a $.5 million impact on its consolidated balance sheets and income statements. Pepco's management consults with its actuaries and investment consultants when selecting its plan assumptions.

     Pepco follows the guidance of SFAS No. 87, "Employers' Accounting for Pensions," and SFAS No. 106, "Employers' Accounting for Post-retirement Benefits Other Than Pensions," when accounting for these benefits. Under these accounting standards, assumptions are made regarding the valuation of benefit obligations and the performance of plan assets. In accordance with these standards, the impact of changes in these assumptions and the difference between actual and expected or estimated results on pension and post-retirement obligations is generally recognized over the working lives of the employees who benefit under the plans rather than immediately recognized in the income statement.

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     Regulation of Power Delivery Operations

     The requirements of SFAS No. 71 apply to Pepco's business. Pepco believes that the judgment involved in accounting for its regulated activities represent "Critical Accounting Estimates" because (i) a significant amount of judgment is required (including but not limited to the interpretation of laws and regulatory commission orders) to assess the probability of the recovery of regulatory assets, (ii) actual results and interpretations could vary from those used in Pepco's estimates and the impact of such variations could be material, and (iii) the impact that writing off a regulatory asset would have on Pepco's assets and the net loss related to the charge could be material.

RISK FACTORS

     The business of Pepco is subject to numerous risks and uncertainties, including the events or conditions identified below. The occurrence of one or more of these events or conditions could have an adverse effect on the business of Pepco, including, depending on the circumstances, its results of operations and financial condition.

Pepco is a public utility that is subject to substantial governmental regulation. If Pepco receives unfavorable regulatory treatment, Pepco's business could be negatively affected.

     Pepco's utility business is subject to regulation by various federal, state and local regulatory agencies that significantly affects its operations. Pepco's operations are regulated in Maryland by the MPSC and in Washington, D.C. by the DCPSC with respect to, among other things, the rates it can charge retail customers for the delivery of electricity. In addition, the rates that Pepco can charge for electricity transmission are regulated by FERC. Pepco cannot change delivery or transmission rates without approval by the applicable regulatory authority. While the approved delivery and transmission rates are intended to permit Pepco to recover its costs of service and earn a reasonable rate of return, Pepco's profitability is affected by the rates it is able to charge. In addition, if the costs incurred by Pepco in operating its transmission and distribution facilities exceed the allowed amounts for costs included in the approved rate s, Pepco's financial results will be adversely affected.

     Pepco also is required to have numerous permits, approvals and certificates from governmental agencies that regulate its business. Pepco believes that it has obtained or sought renewal of the material permits, approvals and certificates necessary for its existing operations and that its business is conducted in accordance with applicable laws; however, Pepco is unable to predict the impact of future regulatory activities of any of these agencies on its business. Changes in or reinterpretations of existing laws or regulations, or the imposition of new laws or regulations, may require Pepco to incur additional expenses or to change the way it conducts its operations.

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Pepco's business could be adversely affected by the Mirant bankruptcy.

     In 2000, Pepco sold substantially all of its electricity generation assets to Mirant. As part of the sale, Pepco entered into several ongoing contractual arrangements with Mirant and certain of its subsidiaries. On July 14, 2003, Mirant 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. Depending on the outcome of the proceedings, the Mirant bankruptcy could adversely affect Pepco's business. See "Relationship with Mirant Corporation."

Pepco could be required to make additional divestiture proceeds gain-sharing payments to customers in the District of Columbia and Maryland.

     Pepco currently is involved in regulatory proceedings in Maryland and the District of Columbia related to the sharing of the net proceeds from the sale of its generation-related assets. The principal issue in the proceedings is whether Pepco should be required to share with customers the excess deferred income taxes and accumulated deferred investment tax credits 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. Depending on the outcome of the proceedings, Pepco could be required to make additional gain-sharing payments to customers and payments to the IRS in the amount of the associated accumulated deferred investment tax credits, and Pepco might be unable to use accelerated depreciation on District of Columbia and Maryland allocated or assigned property. See "Management's Discussion and Analysis of Financial Condition an d Results of Operations -- Regulatory and Other Matters."

The operating results of Pepco fluctuate on a seasonal basis and can be adversely affected by changes in weather.

     Pepco's electric utility business is seasonal and weather patterns can have a material impact on its operating performance. Demand for electricity is generally greater in the summer months associated with cooling and the winter months associated with heating as compared to other times of the year. Accordingly, Pepco historically has generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.

Pepco's facilities may not operate as planned or may require significant maintenance expenditures, which could decrease its revenues or increase its expenses.

     Operation of transmission and distribution facilities involves many risks, including the breakdown or failure of equipment, accidents, labor disputes and performance below expected levels. Older facilities and equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures for additions or upgrades to keep them operating at peak efficiency, to comply with changing environmental requirements, or to provide reliable operations. Natural disasters and weather-related incidents, including tornadoes, hurricanes and snow and ice storms, also can disrupt transmission and distribution delivery systems. Operation of transmission and distribution facilities below expected capacity levels can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance. Furthermore, if Pepco is unable to perform its contractual obligat ions for any of these reasons, it may incur penalties or damages.

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Pepco's transmission facilities are interconnected with the facilities of other transmission facility owners whose actions could have a negative impact on Pepco's operations.

     The transmission facilities of Pepco are directly interconnected with the transmission facilities of contiguous utilities and as such are part of an interstate power transmission grid. FERC has designated a number of regional transmission operators to coordinate the operation of portions of the interstate transmission grid. Pepco is a member of PJM, which is the regional transmission operator that coordinates the movement of electricity in all or parts of Delaware, Maryland, New Jersey, Ohio, Pennsylvania, Virginia, West Virginia and the District of Columbia. Pepco operates its transmission facilities under the direction and control of PJM. PJM and the other regional transmission operators have established sophisticated systems that are designed to ensure the reliability of the operation of transmission facilities and prevent the operations of one utility from having an adverse impact on the operations of the other utilities. Howeve r, the systems put in place by PJM and the other regional transmission operators may not always be adequate to prevent problems at other utilities from causing service interruptions in the transmission facilities of Pepco. If Pepco were to suffer such a service interruption, it could have a negative impact on its business.

The cost of compliance with environmental laws is significant and new environmental laws may increase Pepco's expenses.

     Pepco's operations are subject to extensive federal, state and local environmental statutes, rules and regulations, relating to air quality, water quality, waste management, natural resources, site remediation, and health and safety. These laws and regulations require Pepco to incur expenses to, among other things, conduct site remediation and perform environmental monitoring. Pepco also may be required to pay significant remediation costs with respect to third party sites. If Pepco fails to comply with applicable environmental laws and regulations, even if caused by factors beyond its control, such failure could result in the assessment of civil or criminal penalties and liabilities and the need to expend significant sums to come into compliance.

     In addition, Pepco incurs costs to obtain and comply with a variety of environmental permits, licenses, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval or if Pepco fails to obtain, maintain or comply with any such approval, operations at affected facilities could be halted or subjected to additional costs.

     New environmental laws and regulations, or new interpretations of existing laws and regulations, could impose more stringent limitations on Pepco's operations or require it to incur significant additional costs. Pepco's current compliance strategy may not successfully address the relevant standards and interpretations of the future.

Changes in technology may adversely affect Pepco's electricity delivery businesses.

     Increased conservation efforts and advances in technology could reduce demand for electricity supply and distribution, which could adversely affect Pepco's business. In addition, changes in technology also could alter the channels through which retail electric customers buy electricity, which could adversely affect Pepco's business.

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Acts of terrorism could adversely affect Pepco's business.

     The threat of or actual acts of terrorism may affect Pepco's operations in unpredictable ways and may cause changes in the insurance markets, force Pepco to increase security measures and cause disruptions of power markets. If any of Pepco's transmission or distribution facilities were to be a direct target, or an indirect casualty, of an act of terrorism, its operations could be adversely affected. Instability in the financial markets as a result of terrorism also could affect the ability of Pepco to raise needed capital.

Pepco's insurance coverage may not be sufficient to cover all casualty losses that it might incur.

     Pepco currently has insurance coverage for its facilities and operations in amounts and with deductibles that it considers appropriate. However, there is no assurance that such insurance coverage will be available in the future on commercially reasonable terms. In addition, some risks, such as weather related casualties, may not be insurable. In the case of loss or damage to property, plant or equipment, there is no assurance that the insurance proceeds, if any, received will be sufficient to cover the entire cost of replacement or repair.

Pepco may be adversely affected by economic conditions.

     Periods of slowed economic activity generally result in decreased demand for power, particularly by industrial and large commercial customers. As a consequence, recessions or other downturns in the economy may result in decreased revenues and cash flows for Pepco.

Pepco is dependent on its ability to successfully access capital markets. An inability to access capital may adversely affect its business.

     Pepco relies on access to both short-term money markets and longer-term capital markets as a source of liquidity and to satisfy its capital requirements not satisfied by the cash flow from its operations. Capital market disruptions, or a downgrade in Pepco's credit ratings, would increase the cost of borrowing or could adversely affect its ability to access one or more financial markets. Disruptions to the capital markets could include, but are not limited to:

· recession or an economic slowdown;

· the bankruptcy of one or more energy companies;

· significant increases in the prices for oil or other fuel;

· a terrorist attack or threatened attacks; or

· a significant transmission failure.

Pepco may be required to, or may elect to, make significant cash contributions to the Retirement Plan.

     Pepco follows the guidance of SFAS No. 87, "Employers' Accounting for Pensions" in accounting for pension benefits under the Retirement Plan, a non-contributory defined benefit plan in which Pepco's employees participate. In accordance with these accounting standards, Pepco makes assumptions regarding the valuation of benefit obligations and the performance of plan assets. Changes in assumptions such as the use of a different discount rate or expected return on plan assets, affects the calculation of projected benefit obligations, accumulated benefit obligation, reported pension liability on Pepco's balance sheet, and reported annual net periodic pension benefit cost on Pepco's income statement.

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     Furthermore, as a result of actual pension plan experience being different from expected, the accumulated benefit obligation (ABO) could be greater than the fair value of pension plan assets. If this were to occur, Pepco could be required to recognize an additional minimum liability as prescribed by SFAS No. 87. The liability would be recorded as a reduction to common equity through a charge to Other Comprehensive Income (OCI), and would not affect net income for the year. The charge to OCI would be restored through common equity in future periods when the fair value of plan assets exceeded the accumulated benefit obligation. PHI's funding policy is to make cash contributions to the pension plan sufficient for plan assets to exceed the ABO, and avoid the recognition of an additional minimum liability.

     Use of alternative assumptions could also impact the expected future cash funding requirements for the Retirement Plan if it did not meet the minimum funding requirements of ERISA.

Energy companies are subject to adverse publicity, which may render Pepco vulnerable to negative regulatory and litigation outcomes.

     The energy sector has been among the sectors of the economy that have been the subject of highly publicized allegations of misconduct in recent years. In addition, many utility companies have been publicly criticized for their performance during recent natural disasters and weather related incidents. Adverse publicity of this nature may render legislatures, regulatory authorities, and tribunals less likely to view energy companies such as Pepco in a favorable light and may cause them to be susceptible to adverse outcomes with respect to decisions by such bodies.

Because Pepco is a wholly owned subsidiary of PHI, PHI can exercise substantial control over its dividend policy and business and operations.

     All of the members of Pepco's board of directors, as well as many of Pepco's executive officers, are officers of PHI. Among other decisions, Pepco's board is responsible for decisions regarding payment of dividends, financing and capital raising activities, and acquisition and disposition of assets. Within the limitations of applicable law, including limitations imposed by PUHCA, and subject to the financial covenants under Pepco's outstanding debt instruments, Pepco's board of directors will base its decisions concerning the amount and timing of dividends, and other business decisions, on Pepco's earnings, cash flow and capital structure, but may also take into account the business plans and financial requirements of PHI and its other subsidiaries.

FORWARD LOOKING STATEMENTS

     Some of the statements contained in this Form 10-K are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act 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 our or our industry's actual results, lev els of

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

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

· Prevailing governmental policies and regulatory actions affecting the energy industry, including 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 our 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 Annual 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 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.

     Pepco undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. 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

RESULTS OF OPERATIONS

     The Results of Operations discussion for DPL is presented only for the year ended December 31, 2004, in accordance with General Instruction I(2)(a). All dollar amounts are in millions.

Electric Operating Revenue

	2004	2003	Change
Regulated T&D Electric Revenue	$  369.7	$  383.7	$(14.0)
Default Supply Revenue	628.2	610.6	17.6
Other Electric Revenue	19.7	68.4	(48.7)
Total Electric Operating Revenue	$1,017.6	$1,062.7	$(45.1)

     The table above shows the amounts of Electric Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue). Regulated T&D (Transmission & Distribution) Electric Revenue includes revenue DPL receives for delivery of electricity to its customers. Default Supply Revenue (DSR), also known as Standard Offer Service (SOS) in Maryland and Provider of Last Resort (POLR) in Delaware, includes revenue DPL receives from the supply of electricity at regulated rates. 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, a nd collection fees.

     Regulated T&D Electric Revenue

     Regulated T&D Electric Revenue decreased by $14.0 million primarily due to the following unfavorable variances: (i) $6.6 million lower PJM network transmission revenue (offset in Fuel and Purchased Energy), (ii) $6.1 million lower industrial sales and average customer usage, (iii) $2.1 million related to Delaware competitive transition charge that ended in 2003, offset by (iv) $.8 million favorable weather impact. Delivered sales for the year ended December 31, 2004 were approximately 13,902,000 MwH compared to approximately 14,032,000 MwH for the comparable period in 2003. Cooling degree days increased by 1.8% while heating degree days decreased by 4.6% for the year ended December 31, 2004 compared to the same period in 2003.

     Default Supply Revenue

     Default Supply Revenue increased by $17.6 million primarily due to the following: (i) $32.9 million due to higher retail energy rates, the result of effective rate increases in Delaware beginning in October 2003 and in Maryland beginning in June and July 2004, offset by (ii) $12.2 million increased customer migration, and (iii) $2.7 million unfavorable weather impact.

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     For the twelve months ended December 31, 2004, DPL's Delaware customers served by an alternate supplier represented 6% of DPL's total Delaware load and DPL's Maryland customers served by alternate suppliers represented 23% of DPL's total Maryland load. For the twelve months ended December 31, 2003, the DPL's Delaware customers served by an alternate supplier represented 6% of DPL's total Delaware load and DPL's Maryland customers served by alternate suppliers represented 10% of DPL's total Maryland load.

     Default Supply sales for the year ended December 31, 2004 were approximately 12,008,000 MwH compared to approximately 12,362,000 MwH for the comparable period in 2003.

     Other Electric Revenue

     Other Electric Revenue decreased by $48.7 million primarily due to $43.0 million decrease in sales (offset in Fuel and Purchased Energy) to the Delaware Municipal Electric Corporation (DMEC) due to contract expiration on December 31, 2003 and $5.7 million lower other non-operating revenue.

Natural Gas Operating Revenue

	2004	2003	Change
Regulated Gas Revenue	$169.1	$150.2	$18.9
Other Gas Revenue	58.6	40.8	17.8
Total Natural Gas Operating Revenue	$227.7	$191.0	$36.7

     The table above shows the amounts of Natural Gas Operating Revenue from sources that were subject to price regulation (Regulated Gas Revenue) and that were generally not subject to price regulation (Other Gas Revenue). Regulated Gas Revenue includes on-system natural gas sales and the transportation of natural gas for customers. Other Gas Revenue includes off-system natural gas sales and the resale of excess gas or system capacity.

     Regulated Gas Revenue

     Regulated Gas Revenue increased by $18.9 million primarily due to the following: (i) $21.0 million increase in the Gas Cost Rate due to higher natural gas commodity costs; this was effective November 1, 2003; (ii) $8.2 million increase in Gas Base Rates due to higher operating expenses and costs of capital; this was effective December 9, 2003; (iii) $2.0 million adjustment to unbilled revenues in 2003; and partially offset by (iv) $9.4 million decrease due to 2003 being significantly colder than normal, and (v) $2.9 million reduction related to lower industrial sales. For the year ended December 31, 2004, gas sales were approximately 21,600,000 Mcf as compared to approximately 22,900,000 Mcf for the comparable period in 2003. For the year ended December 31, 2004, heating degree days decreased 7.1% for the year ended December 31, 2004 as compared to the same period in 2003.

     Other Gas Revenue

     Other Gas Revenue increased by $17.8 million largely related to an increase in off-system sales revenues of $17.3 million. The gas sold off-system was made available by warmer winter weather and, as a result, reduced customer demand. (offset in Gas Purchased)

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Operating Expenses

     Fuel and Purchased Energy

     Fuel and Purchased Energy decreased by $42.7 million to $656.8 million in 2004 from $699.5 million in 2003 due primarily to: (i)$43.0 million from the expiration of the DMEC contract in December 2003 (offset in Other Electric Revenue), (ii) $4.3 million reduction in PJM network transmission costs (partial offset in Regulated T&D Electric Revenue) offset by (iii) $4.6 million higher average energy costs, the result of the new Default Supply rates for Maryland beginning in June and July 2004.

     Gas Purchased

    Gas Purchased increased by $30.2 million to $162.5 million in 2004 from $132.3 million in 2003. Regulated gas purchased primarily resulted from the following: (i) net $20.4 million increase (substantially offset in revenue) from the settlement of financial hedges (entered into as part of DPL's regulated Natural Gas Hedge program), (ii) offset by a $7.2 million decrease in on- system purchases due to warmer weather. In addition, other gas purchased increased by $17.0 million due to the increase in off-system sales (offset in Other Gas Revenue).

     Other Operation and Maintenance

     Other Operation and Maintenance decreased by $7.8 million to $179.1 million in 2004 from $186.9 million in 2003. The decrease primarily resulted from (i) $3.3 million lower billing system IT costs, (ii) $2.5 million incremental storm costs primarily related to one time charges as a result of Hurricane Isabel in September 2003, (iii) $2.5 million decrease in uncollectible reserve, (iv) $2.4 million lower pension costs in 2004,and (v) $1.1 million decrease other costs, offset by (vi) $2.4 million higher severance costs in 2004 and (vii) $2.0 million for Sarbanes-Oxley external compliance costs.

     Other Taxes

     Other Taxes decreased by $8.3 million to $27.6 million in 2004 from $35.9 million in 2003. The decrease primarily resulted from property tax true-ups.

     Other Income (Expenses)

     Other Expenses decreased by $3.6 million to a net expense of $29.4 million in 2004 from a net expense of $33.0 million in 2003. This decrease is primarily due to a $4.2 million decrease in interest charges due to a reduction in long-term debt, partially offset by a $1.2 million increase in short-term interest charges.

Preferred Stock Dividend Requirements

     Preferred Stock Dividend Requirements decreased by $2.8 million from 2003. This is attributable to SFAS No. 150, which requires that dividends on Mandatorily Redeemable Serial Preferred Stock declared subsequent to July 1, 2003, be recorded as interest expense.

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Income Tax Expense

     DPL's effective tax rate for 2004 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), changes in estimates related to tax liabilities of prior tax years subject to audit and the flow-through of certain book tax depreciation differences (which was the primary reason for the higher effective tax rate as compared to 2003) partially offset by the flow-through of Deferred Investment Tax Credits.

     DPL's effective tax rate for 2003 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), changes in estimates related to tax liabilities of prior tax years subject to audit, partially offset by the flow-through of Deferred Investment Tax Credits.

RISK FACTORS

     The business of DPL is subject to numerous risks and uncertainties, including the events or conditions identified below. The occurrence of one or more of these events or conditions could have an adverse effect on the business of DPL, including, depending on the circumstances, its results of operations and financial condition.

DPL is a public utility that is subject to substantial governmental regulation. If DPL receives unfavorable regulatory treatment, DPL's business could be negatively affected.

     DPL's utility business is subject to regulation by various federal, state and local regulatory agencies that significantly affects its operations. DPL's operations are regulated in Maryland by the MPSC, in Delaware by the DPSC and in Virginia by the VSCC with respect to, among other things, the rates it can charge retail customers for the delivery of electricity and gas. In addition, the rates that DPL can charge for electricity transmission are regulated by FERC. DPL cannot change delivery or transmission rates without approval by the applicable regulatory authority. While the approved delivery and transmission rates are intended to permit DPL to recover its costs of service and earn a reasonable rate of return, DPL's profitability is affected by the rates it is able to charge. In addition, if the costs incurred by DPL in operating its transmission and distribution facilities exceed the allowed amounts for costs included in the approved r ates, DPL's financial results will be adversely affected.

     DPL also is required to have numerous permits, approvals and certificates from governmental agencies that regulate its business. DPL believes that it has obtained or sought renewal of the material permits, approvals and certificates necessary for its existing operations and that its business is conducted in accordance with applicable laws; however, DPL is unable to predict the impact of future regulatory activities of any of these agencies on its business. Changes in or reinterpretations of existing laws or regulations, or the imposition of new laws or regulations, may require DPL to incur additional expenses or to change the way it conducts its operations.

The operating results of DPL fluctuate on a seasonal basis and can be adversely affected by changes in weather.

     DPL's utility businesses are seasonal and weather patterns can have a material impact on its operating performance. Demand for electricity is

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generally greater in the summer months associated with cooling and demand for electricity and gas is generally greater in the winter months associated with heating as compared to other times of the year. Accordingly, DPL historically has generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.

DPL's facilities may not operate as planned or may require significant maintenance expenditures, which could decrease its revenues or increase its expenses.

     Operation of transmission and distribution facilities involves many risks, including the breakdown or failure of equipment, accidents, labor disputes and performance below expected levels. Older facilities and equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures for additions or upgrades to keep them operating at peak efficiency, to comply with changing environmental requirements, or to provide reliable operations. Natural disasters and weather-related incidents, including tornadoes, hurricanes and snow and ice storms, also can disrupt transmission and distribution delivery systems. Operation of transmission and distribution facilities below expected capacity levels can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance. Furthermore, if DPL is unable to perform its contractual obligations for any of these reasons, it may incur penalties or damages.

DPL's transmission facilities are interconnected with the facilities of other transmission facility owners whose actions could have a negative impact on DPL's operations.

     The electricity transmission facilities of DPL are directly interconnected with the transmission facilities of contiguous utilities and as such are part of an interstate power transmission grid. FERC has designated a number of regional transmission operators to coordinate the operation of portions of the interstate transmission grid. DPL is a member of PJM, which is the regional transmission operator that coordinates the movement of electricity in all or parts of Delaware, Maryland, New Jersey, Ohio, Pennsylvania, Virginia, West Virginia and the District of Columbia. DPL operates its transmission facilities under the direction and control of PJM. PJM and the other regional transmission operators have established sophisticated systems that are designed to ensure the reliability of the operation of transmission facilities and prevent the operations of one utility from having an adverse impact on the operations of the other utilities. However , the systems put in place by PJM and the other regional transmission operators may not always be adequate to prevent problems at other utilities from causing service interruptions in the transmission facilities of DPL. If DPL were to suffer such a service interruption, it could have a negative impact on its business.

The cost of compliance with environmental laws is significant and new environmental laws may increase DPL's expenses.

     DPL's operations are subject to extensive federal, state and local environmental statutes, rules and regulations, relating to air quality, water quality, spill prevention, waste management, natural resources, site remediation, and health and safety. These laws and regulations require DPL to incur expenses to, among other things, conduct site remediation and obtain permits. DPL also may be required to pay significant remediation costs with respect to third party sites. If DPL fails to comply with applicable environmental laws and regulations, even if caused by factors

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beyond its control, such failure could result in the assessment of civil or criminal penalties and liabilities and the need to expend significant sums to come into compliance.

     In addition, DPL incurs costs to obtain and comply with a variety of environmental permits, licenses, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval or if DPL fails to obtain, maintain or comply with any such approval, operations at affected facilities could be halted or subjected to additional costs.

     New environmental laws and regulations, or new interpretations of existing laws and regulations, could impose more stringent limitations on DPL's operations or require it to incur significant additional costs. DPL's current compliance strategy may not successfully address the relevant standards and interpretations of the future.

Changes in technology may adversely affect DPL's electricity and gas delivery businesses.

     Increased conservation efforts and advances in technology could reduce demand for electricity and gas supply and distribution, which could adversely affect DPL's business. In addition, changes in technology also could alter the channels through which retail electric customers buy electricity, which could adversely affect DPL's business.

Acts of terrorism could adversely affect DPL's business.

     The threat of or actual acts of terrorism may affect DPL's operations in unpredictable ways and may cause changes in the insurance markets, force DPL to increase security measures and cause disruptions of power markets. If any of DPL's transmission or distribution facilities were to be a direct target, or an indirect casualty, of an act of terrorism, its operations could be adversely affected. Instability in the financial markets as a result of terrorism also could affect the ability of DPL to raise needed capital.

DPL's insurance coverage may not be sufficient to cover all casualty losses that it might incur.

     DPL currently has insurance coverage for its facilities and operations in amounts and with deductibles that it considers appropriate. However, there is no assurance that such insurance coverage will be available in the future on commercially reasonable terms. In addition, some risks, such as weather related casualties, may not be insurable. In the case of loss or damage to property, plant or equipment, there is no assurance that the insurance proceeds, if any, received will be sufficient to cover the entire cost of replacement or repair.

DPL may be adversely affected by economic conditions.

     Periods of slowed economic activity generally result in decreased demand for power, particularly by industrial and large commercial customers. As a consequence, recessions or other downturns in the economy may result in decreased revenues and cash flows for DPL.

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DPL is dependent on its ability to successfully access capital markets. An inability to access capital may adversely affect its business.

     DPL relies on access to both short-term money markets and longer-term capital markets as a source of liquidity and to satisfy its capital requirements not satisfied by the cash flow from its operations. Capital market disruptions, or a downgrade in DPL's credit ratings, would increase the cost of borrowing or could adversely affect its ability to access one or more financial markets. Disruptions to the capital markets could include, but are not limited to:

· recession or an economic slowdown;

· the bankruptcy of one or more energy companies;

· significant increases in the prices for oil or other fuel;

· a terrorist attack or threatened attacks; or

· a significant transmission failure.

DPL may be required to, or may elect to, make significant cash contributions to the Retirement Plan.

     DPL follows the guidance of SFAS No. 87, "Employers' Accounting for Pensions" in accounting for pension benefits under the Retirement Plan, a non-contributory defined benefit plan in which DPL's employees participate. In accordance with these accounting standards, DPL makes assumptions regarding the valuation of benefit obligations and the performance of plan assets. Changes in assumptions such as the use of a different discount rate or expected return on plan assets, affects the calculation of projected benefit obligations, accumulated benefit obligation, reported pension liability on DPL's balance sheet, and reported annual net periodic pension benefit cost on DPL's income statement.

     Furthermore, as a result of actual pension plan experience being different from expected, the accumulated benefit obligation (ABO) could be greater than the fair value of pension plan assets. If this were to occur, DPL could be required to recognize an additional minimum liability as prescribed by SFAS No. 87. The liability would be recorded as a reduction to common equity through a charge to Other Comprehensive Income (OCI), and would not affect net income for the year. The charge to OCI would be restored through common equity in future periods when the fair value of plan assets exceeded the accumulated benefit obligation. PHI's funding policy is to make cash contributions to the pension plan sufficient for plan assets to exceed the ABO, and avoid the recognition of an additional minimum liability.

     Use of alternative assumptions could also impact the expected future cash funding requirements for the Retirement Plan if it did not meet the minimum funding requirements of ERISA.

Energy companies are subject to adverse publicity, which may render DPL vulnerable to negative regulatory and litigation outcomes.

     The energy sector has been among the sectors of the economy that have been the subject of highly publicized allegations of misconduct in recent years. In addition, many utility companies have been publicly criticized for their performance during recent natural disasters and weather related incidents. Adverse publicity of this nature may render legislatures, regulatory authorities, and tribunals less likely to view energy companies

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such as DPL in a favorable light and may cause them to be susceptible to adverse outcomes with respect to decisions by such bodies.

Because DPL is an indirect, wholly owned subsidiary of PHI, PHI can exercise substantial control over its dividend policy and business and operations.

     All of the members of DPL's board of directors, as well as many of DPL's executive officers, are officers of PHI. Among other decisions, DPL's board is responsible for decisions regarding payment of dividends, financing and capital raising activities, and acquisition and disposition of assets. Within the limitations of applicable law, including limitations imposed by PUHCA, and subject to the financial covenants under DPL's outstanding debt instruments, DPL's board of directors will base its decisions concerning the amount and timing of dividends, and other business decisions, on DPL's earnings, cash flow and capital structure, but may also take into account the business plans and financial requirements of PHI and its other subsidiaries.

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

ATLANTIC CITY ELECTRIC COMPANY

RESULTS OF OPERATIONS

     The Results of Operations discussion for ACE is presented only for the year ended December 31, 2004, in accordance with General Instruction I(2)(a). All dollar amounts are in millions.

Operating Revenue

	2004	2003	Change
Regulated T&D Electric Revenue	$351.6	$350.5	$  1.1
Default Supply Revenue	962.0	856.3	105.7
Other Electric Revenue	19.6	29.2	(9.6)
Total Operating Revenue	$1,333.2	$1,236.0	$ 97.2

     The table above shows the amounts of Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue). Regulated T&D (Transmission & Distribution) Electric Revenue includes revenue ACE receives for delivery of electricity to its customers. Default Supply Revenue (DSR), also known as Basic Generation Service (BGS) includes revenue ACE receives from the supply of electricity at regulated rates. The costs related to the supply of electricity are included in Fuel and Purchased Energy. Also included in DSR is revenue from non-utility generators (NUGs), transition bond charges (TBC), market transition charges (MTC) and other restructuring related revenues (see Deferred Electric Service Cost). Other 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 Revenue

     Regulated T&D Electric Revenue increased by $1.1 million primarily due to the following: (i) $9.0 million increased average customer usage, (ii) $4.8 million increase in higher average effective rates, offset by, (iii) $5.5 million lower PJM network transmission revenue (offset in Fuel and Purchased Energy), (iv) $5.1 million lower transmission revenue related to increased customer migration, and (v) $2.1 million unfavorable weather impact. Delivered sales for the year ended December 31, 2004 were approximately 9,874,000 MwH compared to approximately 9,643,000 MwH for the comparable period in 2003. Cooling degree days decreased by .5% and heating degree days decreased by 7.9% for the year ended December 31, 2004 compared to the same period in 2003.

     Default Supply Revenue

     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 $105.7 million increase in DSR resulted from the following: (i) $83.1 million of higher wholesale energy revenues due to higher market prices in 2004, (ii) $76.3 million due to higher

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effective rates as the result of an increase in BGS retail energy rates beginning in June 2004 and an increase in net NUG and MTC rates beginning in August 2003, (iii) $24.4 million of higher average customer use, partially offset by (iv) $68.9 million decrease related to increased customer migration, and (v) $9.2 million unfavorable weather impact.

     For the twelve months ended December 31, 2004, ACE's New Jersey customers served by an alternate supplier represented 22% of ACE's total load. For the twelve months ended December 31, 2003, ACE's New Jersey customers served by an alternate supplier represented 11% of ACE's total load.

     Default Supply sales for the twelve months ended December 31, 2004 were approximately 7,669,000 MwH compared to approximately 8,597,000 MwH for the comparable period in 2003.

     Other Electric Revenue

     Other Electric Revenue decreased by $9.6 million primarily due to the following: (i) $5.2 million decrease in inter-company revenue related to Deepwater tolling transaction between ACE and CEH, (ii) $3.2 million fuel oil sale in the first quarter of 2003, and (iii) $.6 million lower customer requested work.

Operating Expenses

     Fuel and Purchased Energy

     Fuel and Purchased Energy increased by $28.0 million to $806.7 million in 2004 from $778.7 million in 2003. This increase was primarily due to: (i) $36.4 million higher average costs, the result of the new Default Supply rates for New Jersey beginning in June 2004 and offset by (ii) $8.4 million reduced PJM network transmission costs (partial offset in Regulated T&D Electric Revenue).

     Other Operation and Maintenance

     Other Operation and Maintenance decreased by $15.3 million to $192.7 million in 2004 from $208.0 million in 2003. The decrease primarily resulted from: (i) $10.2 million for Deepwater, plant transferred to CE in 2004; (ii) $6.8 million for reduced pension costs in 2004; (iii) $3.5 million related to billing system IT costs; (iv) $2.0 million primarily for Default Supply and Demand Side Management related costs; (v) $1.0 million incremental storm costs primarily related to one time charges as a result of Hurricane Isabel in September 2003, partially offset by (vi) $4.6 million severance costs in 2004; (vii) $1.5 million for electric system maintenance; (viii) $2.0 million for Sarbanes-Oxley external compliance costs; and (ix) $.7 million for bad debt expense.

     Depreciation and Amortization

     Depreciation and Amortization expenses increased by $20.3 million to $132.8 million in 2004 from $112.5 million in 2003 primarily due to: (i) $12.8 million increase for amortization of bondable transition property as a result of additional transition bonds issued in December 2003; (ii) $3.8 million for the amortization of the deferred service costs balance which began in August 2003, (iii) $2.4 million increase for amortization of a regulatory tax asset related to New Jersey stranded costs, and (iv) $1.3 million other various items.

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     Other Taxes

     Other Taxes decreased by $3.7 million to $20.1 million in 2004 from $23.8 million in 2003. The decrease primarily resulted from a $3.3 million New Jersey delivery tax expense true-up in 2004.

     Deferred Electric Service Costs

     Deferred Electric Service Costs (DESC), which relates only to ACE, increased by $43.3 million to $36.3 million for the year ended December 31, 2004 from a $7.0 million credit to operating expense for the year ended December 31, 2003. The $43.3 million increase represents a net over-recovery associated with New Jersey NUGs, MTC and other restructuring items. Additionally, the 2003 period contained a $27.5 million charge related to the New Jersey deferral disallowance regarding the procurement of fuel and purchased energy. Customers in New Jersey who do not choose a competitive supplier receive default electricity supply from suppliers selected through auctions approved by the NJBPU. ACE's rates for the recovery of these costs are reset annually. On ACE's balance sheet a regulatory asset includes an under-recovery of $99.4 million as of December 31, 2004. This amount is net of a $46.1 million reserve on previously disallowed items under appe al.

     Gain on Sale of Assets

     The Gain on Sale of Assets increase of $14.7 million in 2004 is due to a settlement with the City of Vineland, New Jersey. During the second quarter of 2004, ACE and the City of Vineland finalized condemnation settlement under which ACE transferred to the City of Vineland its distribution assets within the geographical limits of the City of Vineland and related customer accounts. The transaction resulted in a pre-tax gain of approximately $14.7 million, which is recorded as a reduction to operating expenses in the line item entitled "gain on sale of assets" on the consolidated statements of earnings.

     Other Income (Expenses)

     Other Expenses increased by $3.0 million to a net expense of $52.4 million in 2004 from a net expense of $49.4 million in 2003. This increase is primarily due to the following: (i) $5.5 million increase in interest expense on Transition Bonds issued by ACE Funding due to additional transition bonds issued in December, 2003, partially offset by; (ii) $2.1 million decrease in income from customers to recover income tax expense on contributions in aid of construction.

Preferred Stock Dividend Requirements

     Preferred Stock Dividend Requirements decreased by $1.8 million from 2003. This was attributable to SFAS No. 150, which requires that dividends on Mandatorily Redeemable Serial Preferred Stock declared subsequent to July 1, 2003, be recorded as interest expense.

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Income Tax Expense

     ACE's effective tax rate for 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), changes in estimates related to tax liabilities of prior tax years subject to audit, partially offset by the flow-through of Deferred Investment Tax Credits.

     ACE's effective tax rate for 2003 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), changes in estimates related to tax liabilities of prior tax years subject to audit, partially offset by the flow-through of Deferred Investment Tax Credits.

Extraordinary Item

     In July 2003, the New Jersey Board of Public Utilities (NJBPU) approved the determination of stranded costs related to ACE's January 31, 2003, petition relating to its B.L. England generating facility. The NJBPU approved recovery of $149.5 million. As a result of the order, ACE reversed $10.0 million of accruals for the possible disallowances related to these stranded costs. The credit to income of $5.9 million is classified as an extraordinary gain in ACE's financial statements, since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.

RISK FACTORS

     The business of ACE is subject to numerous risks and uncertainties, including the events or conditions identified below. The occurrence of one or more these events or conditions could have an adverse effect on the business of ACE, including, depending on the circumstances, its results of operations and financial condition.

ACE is a public utility that is subject to substantial governmental regulation. If ACE receives unfavorable regulatory treatment, ACE's business could be negatively affected.

     ACE's utility business is subject to regulation by various federal, state and local regulatory agencies that significantly affects its operations. ACE's operations are regulated by the NJBPU with respect to, among other things, the rates it can charge retail customers for the delivery of electricity. In addition, the rates that ACE can charge for electricity transmission are regulated by FERC. ACE cannot change delivery or transmission rates without approval by the applicable regulatory authority. While the approved delivery and transmission rates are intended to permit ACE to recover its costs of service and earn a reasonable rate of return, ACE's profitability is affected by the rates it is able to charge. In addition, if the costs incurred by ACE in operating its transmission and distribution facilities exceed the allowed amounts for costs included in the approved rates, ACE's financial results will be adversely affected.

     ACE also is required to have numerous permits, approvals and certificates from governmental agencies that regulate its business. ACE believes that it has obtained or sought renewal of the material permits, approvals and certificates necessary for its existing operations and that its business is conducted in accordance with applicable laws; however, ACE is unable to predict the impact of future regulatory activities of

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any of these agencies on its business. Changes in or reinterpretations of existing laws or regulations, or the imposition of new laws or regulations, may require ACE to incur additional expenses or to change the way it conducts its operations.

The operating results of ACE fluctuate on a seasonal basis and can be adversely affected by changes in weather.

     ACE's electric utility business is seasonal and weather patterns can have a material impact on its operating performance. Demand for electricity is generally greater in the summer months associated with cooling and the winter months associated with heating as compared to other times of the year. Accordingly, ACE historically has generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.

ACE's facilities may not operate as planned or may require significant maintenance expenditures, which could decrease its revenues or increase its expenses.

     Operation of generation, transmission and distribution facilities involves many risks, including the breakdown or failure of equipment, accidents, labor disputes and performance below expected levels. Older facilities and equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures for additions or upgrades to keep them operating at peak efficiency, to comply with changing environmental requirements, or to provide reliable operations. Natural disasters and weather-related incidents, including tornadoes, hurricanes and snow and ice storms, also can disrupt generation, transmission and distribution delivery systems. Operation of generation, transmission and distribution facilities below expected capacity levels can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance. Furthermore, if ACE is unable to perf orm its contractual obligations for any of these reasons, it may incur penalties or damages.

ACE's transmission facilities are interconnected with the facilities of other transmission facility owners whose actions could have a negative impact on the ACE's operations.

     The transmission facilities of ACE are directly interconnected with the transmission facilities of contiguous utilities and as such are part of an interstate power transmission grid. FERC has designated a number of regional transmission operators to coordinate the operation of portions of the interstate transmission grid. ACE is a member of PJM, which is the regional transmission operator that coordinates the movement of electricity in all or parts of Delaware, Maryland, New Jersey, Ohio, Pennsylvania, Virginia, West Virginia and the District of Columbia. ACE operates its transmission facilities under the direction and control of PJM. PJM and the other regional transmission operators have established sophisticated systems that are designed to ensure the reliability of the operation of transmission facilities and prevent the operations of one utility from having an adverse impact on the operations of the other utilities. However, the system s put in place by PJM and the other regional transmission operators may not always be adequate to prevent problems at other utilities from causing service interruptions in the transmission facilities of ACE. If ACE were to suffer such a service interruption, it could have a negative impact on its business.

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The cost of compliance with environmental laws is significant and new environmental laws may increase ACE's expenses.

     ACE's operations are subject to extensive federal, state and local environmental statutes, rules and regulations, relating to air quality, water quality, spill prevention, waste management, natural resources, site remediation, and health and safety. These laws and regulations require ACE to incur expenses to, among other things, conduct site remediation and obtain permits. ACE also may be required to pay significant remediation costs with respect to third party sites. If ACE fails to comply with applicable environmental laws and regulations, even if caused by factors beyond its control, such failure could result in the assessment of civil or criminal penalties and liabilities and the need to expend significant sums to come into compliance.

     In addition, ACE incurs costs to obtain and comply with a variety of environmental permits, licenses, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval or if ACE fails to obtain, maintain or comply with any such approval, operations at affected facilities could be halted or subjected to additional costs.

     New environmental laws and regulations, or new interpretations of existing laws and regulations, could impose more stringent limitations on ACE's operations or require it to incur significant additional costs. ACE's current compliance strategy may not successfully address the relevant standards and interpretations of the future.

Changes in technology may adversely affect ACE's electricity delivery businesses

     Increased conservation efforts and advances in technology could reduce demand for electricity supply and distribution, which could adversely affect ACE's business. In addition, changes in technology also could alter the channels through which retail electric customers buy electricity, which could adversely affect ACE's business.

Acts of terrorism could adversely affect ACE's business.

     The threat of or actual acts of terrorism may affect ACE's operations in unpredictable ways and may cause changes in the insurance markets, force ACE to increase security measures and cause disruptions of power markets. If any of ACE's generation, transmission or distribution facilities were to be a direct target, or an indirect casualty, of an act of terrorism, its operations could be adversely affected. Instability in the financial markets as a result of terrorism also could affect the ability of ACE to raise needed capital.

ACE's insurance coverage may not be sufficient to cover all casualty losses that it might incur.

     ACE currently has insurance coverage for its facilities and operations in amounts and with deductibles that it considers appropriate. However, there is no assurance that such insurance coverage will be available in the future on commercially reasonable terms. In addition, some risks, such as weather related casualties, may not be insurable. In the case of loss or damage to property, plant or equipment, there is no assurance that the insurance proceeds, if any, received will be sufficient to cover the entire cost of replacement or repair.

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ACE may be adversely affected by economic conditions.

     Periods of slowed economic activity generally result in decreased demand for power, particularly by industrial and large commercial customers. As a consequence, recessions or other downturns in the economy may result in decreased revenues and cash flows for ACE.

ACE is dependent on its ability to successfully access capital markets. An inability to access capital may adversely affect its business.

     ACE relies on access to both short-term money markets and longer-term capital markets as a source of liquidity and to satisfy its capital requirements not satisfied by the cash flow from its operations. Capital market disruptions, or a downgrade in ACE's credit ratings, would increase the cost of borrowing or could adversely affect its ability to access one or more financial markets. Disruptions to the capital markets could include, but are not limited to:

· recession or an economic slowdown;

· the bankruptcy of one or more energy companies;

· significant increases in the prices for oil or other fuel;

· a terrorist attack or threatened attacks; or

· a significant transmission failure.

ACE may be required to, or may elect to, make significant cash contributions to the Retirement Plan.

     ACE follows the guidance of SFAS No. 87, "Employers' Accounting for Pensions" in accounting for pension benefits under the Retirement Plan, a non-contributory defined benefit plan in which ACE's employees participate. In accordance with these accounting standards, ACE makes assumptions regarding the valuation of benefit obligations and the performance of plan assets. Changes in assumptions such as the use of a different discount rate or expected return on plan assets, affects the calculation of projected benefit obligations, accumulated benefit obligation, reported pension liability on ACE's balance sheet, and reported annual net periodic pension benefit cost on ACE's income statement.

     Furthermore, as a result of actual pension plan experience being different from expected, the accumulated benefit obligation (ABO) could be greater than the fair value of pension plan assets. If this were to occur, ACE could be required to recognize an additional minimum liability as prescribed by SFAS No. 87. The liability would be recorded as a reduction to common equity through a charge to Other Comprehensive Income (OCI), and would not affect net income for the year. The charge to OCI would be restored through common equity in future periods when the fair value of plan assets exceeded the accumulated benefit obligation. PHI's funding policy is to make cash contributions to the pension plan sufficient for plan assets to exceed the ABO, and avoid the recognition of an additional minimum liability.

     Use of alternative assumptions could also impact the expected future cash funding requirements for the Retirement Plan if it did not meet the minimum funding requirements of ERISA.

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Energy companies are subject to adverse publicity, which may render ACE vulnerable to negative regulatory and litigation outcomes.

     The energy sector has been among the sectors of the economy that have been the subject of highly publicized allegations of misconduct in recent years. In addition, many utility companies have been publicly criticized for their performance during recent natural disasters and weather related incidents. Adverse publicity of this nature may render legislatures, regulatory authorities, and tribunals less likely to view energy companies such as ACE in a favorable light and may cause them to be susceptible to adverse outcomes with respect to decisions by such bodies.

Because ACE is an indirect, wholly owned subsidiary of PHI, PHI can exercise substantial control over its dividend policy and business and operations.

     All of the members of ACE's board of directors, as well as many of ACE's executive officers, are officers of PHI. Among other decisions, ACE's board is responsible for decisions regarding payment of dividends, financing and capital raising activities, and acquisition and disposition of assets. Within the limitations of applicable law, including limitations imposed by PUHCA, and subject to the financial covenants under ACE's outstanding debt instruments, ACE's board of directors will base its decisions concerning the amount and timing of dividends, and other business decisions, on ACE's earnings, cash flow and capital structure, but may also take into account the business plans and financial requirements of PHI and its other subsidiaries.

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Item 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Pepco Holdings

     As of March 2003, Conectiv Energy ceased all proprietary trading activities, which generally consist of the entry into contracts to take a view of market direction, capture market price change, and put capital at risk. PHI's competitive energy segments are no longer engaged in proprietary trading; however, the market exposure under certain contracts entered into prior to cessation of proprietary trading activities was not eliminated due to the illiquid market environment to execute such elimination. These contracts will remain in place until they are terminated and their values are realized as they mature in 2005.

     The competitive energy segments actively engage in commodity risk management activities to reduce their financial exposure to changes in the value of their assets and obligations due to commodity price fluctuations. Certain of these risk management activities are conducted using instruments classified as derivatives under SFAS 133. In addition, the competitive energy segments also manage commodity risk with contracts that are not classified as derivatives. The competitive energy segments' primary risk management objectives are to manage the spread between the cost of fuel used to operate their electric generation plants and the revenue received from the sale of the power produced by those plants and manage the spread between retail sales commitments and the cost of supply used to service those commitments in order to ensure stable and known minimum cash flows and fix favorable prices and margins when they become available. To a lesser exten t, Conectiv Energy also engages in market activities in an effort to profit from short-term geographical price differentials in electricity prices among markets. PHI collectively refers to these energy market activities, including its commodity risk management activities, as "other energy commodity" activities and identifies this activity separate from that of the discontinued proprietary trading activity.

     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 indicative of actual results that may occur.

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Value at Risk Associated with Energy Contracts For the Year Ended December 31, 2004 (Dollars in Millions)
	Proprietary Trading   VaR (1)	VaR for Energy Derivative Contracts (2)	VaR for Competitive Energy Activity (3)
95% confidence level, one-day    holding period, one-tailed(4)
Period end	$ 0.0	$ 4.0	$ 4.3
Average for the period	$ 0.0	$ 6.5	$ 4.6
High	$ 0.1	$11.5	$ 8.9
Low	$ 0.0	$ 2.3	$ 2.1

Notes:
(1)	Includes all remaining proprietary trading contracts entered into prior to cessation of this activity prior to March 2003.
(2)	Includes all derivative contracts under SFAS No. 133, including proprietary trading contracts and derivatives associated with other energy commodity activities.
(3)	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.
(4)	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.

     For additional quantitative and qualitative information on the fair value of energy contracts refer to Note 13, Use of Derivatives in Energy and Interest Rate Hedging Activities in Pepco Holdings' Notes to Consolidated Financial Statements set forth in Item 8 of this Form 10-K.

     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. Dynamic (or economic) 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 purchas e and sales contracts, and load service obligations).

     As of December 31, 2004, based on economic availability projections, 86% of generation output is economically hedged over the next 36 months. Fuel inputs for the same 36 month period are 58% hedged.

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

Schedule of Credit Risk Exposure on Competitive Wholesale Energy Contracts (Dollars in Millions)
	December 31, 2004
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	$260.9	$21.4	$239.5	2	$127.6
Non-Investment Grade	4.3	3.0	1.3	-	-
Split rating	-	-	-	-	-
No External Ratings	17.1	-	17.1	-	-
Credit reserves			$   .6

(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 it 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

QUANTITATIVE AND QUALITATIVE DISCLOSURES

Pepco Holdings

Market Risk

     Market risk represents the potential loss arising from adverse changes in market rates and prices. Certain of Pepco Holdings financial instruments are exposed to market risk in the form of interest rate risk, equity price risk, commodity risk, and credit and nonperformance risk. Pepco Holdings management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. Management reviews any open positions in accordance with strict policies in order to limit exposure to market risk.

Interest Rate Risk

     Pepco Holdings and its subsidiaries floating rate debt is subject to the risk of fluctuating interest rates in the normal course of business. Pepco Holdings manages interest rates through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term and variable rate debt was approximately $1.7 million as of December 31, 2004.

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Commodity Price Risk

     Pepco Holdings is at risk for a decrease in market liquidity to levels that affect its capability to execute its commodity participation strategies. PHI believes the commodity markets to be sufficiently liquid to support its market participation.

     Conectiv's participation in wholesale energy markets includes marketing, trading, and arbitrage activities, which expose Conectiv to commodity market risk. To the extent Conectiv has net open positions, controls are in place that are intended to keep risk exposures within management-approved risk tolerance levels. Conectiv engages in commodity hedging activities to minimize the risk of market fluctuations associated with the purchase and sale of energy commodities (natural gas, petroleum, coal and electricity). The majority of these hedges relate to the procurement of fuel for its power plants, fixing the cash flows from the plant output, and securing power for electric load service. Conectiv's hedging activities are conducted using derivative instruments designated as cash flow hedges, which are designed to reduce the volatility on future cash flows. Conectiv's energy commodity hedging objectives, in accordance with its risk management pol icy, are primarily the assurance of stable and known cash flows and the fixing of favorable prices and margins when they become available. Conectiv manages to the objective of hedging the variability in future cash flows for forecasted energy output from its generation assets at 75% of such forecasted output over a period of 36 months. As of December 2004, Conectiv's average forecasted hedge position for the forward 36 months was projected to meet that objective.

Credit and Nonperformance Risk

     Certain of PHI's subsidiaries' agreements may be subject to credit losses and nonperformance by the counterparties to the agreements. However, PHI anticipates that the counterparties will be able to fully satisfy their obligations under the agreements. PHI's subsidiaries attempt to minimize credit risk exposure to wholesale energy counterparties through, among other things, formal credit policies, regular assessment of counterparty creditworthiness that results in the establishment of a credit limit for each counterparty, monitoring procedures that include stress testing, the use of standard agreements which allow for the netting of positive and negative exposures associated with a single counterparty and collateral requirements under certain circumstances, and has established reserves for credit losses. As of December 31, 2004, credit exposure to wholesale energy counterparties was weighted 92% with investment grade counterparties, 6% with counterparties without external credit quality ratings, and 2% with non-investment grade counterparties.

Pepco

Market Risk

     Market risk represents the potential loss arising from adverse changes in market rates and prices. Certain of Pepco's financial instruments are exposed to market risk in the form of interest rate risk, equity price risk, commodity risk, and credit and nonperformance risk. Pepco's management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. Management reviews any open positions in accordance with strict policies in order to limit exposure to market risk.

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Interest Rate Risk

     Pepco's debt is subject to the risk of fluctuating interest rates in the normal course of business. Pepco manages interest rates through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term debt was approximately $.3 million as of December 31, 2004.

DPL

Market Risk

     Market risk represents the potential loss arising from adverse changes in market rates and prices. Certain of DPL's financial instruments are exposed to market risk in the form of interest rate risk, equity price risk, commodity risk, and credit and nonperformance risk. DPL's management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. Management reviews any open positions in accordance with strict policies in order to limit exposure to market risk.

Interest Rate Risk

     DPL's debt is subject to the risk of fluctuating interest rates in the normal course of business. DPL manages interest rates through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term debt was approximately $.5 million as of December 31, 2004.

ACE

Market Risk

     Market risk represents the potential loss arising from adverse changes in market rates and prices. Certain of ACE's financial instruments are exposed to market risk in the form of interest rate risk, equity price risk, commodity risk, and credit and nonperformance risk. ACE's management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. Management reviews any open positions in accordance with strict policies in order to limit exposure to market risk.

Interest Rate Risk

     ACE's debt is subject to the risk of fluctuating interest rates in the normal course of business. ACE manages interest rates through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term debt was approximately $.2 million as of December 31, 2004.

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Item 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     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
Management's Report on Internal Control   Over Financial Reporting	154	N/A	N/A	N/A
Report of Independent Registered   Public Accounting Firm	155	238	284	321
Consolidated Statements of Earnings	157	239	285	322
Consolidated Statements   of Comprehensive Income	158	240	N/A	N/A
Consolidated Balance Sheets	159	241	286	323
Consolidated Statements of Cash Flows	161	243	288	325
Consolidated Statements   of Shareholders' Equity	162	244	289	326
Notes to Consolidated   Financial Statements	163	245	290	327

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THIS PAGE LEFT INTENTIONALLY BLANK.

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Management's Report on Internal Control Over Financial Reporting

     The management of Pepco Holdings is responsible for establishing and maintaining adequate internal control over financial reporting. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

     Management assessed its internal control over financial reporting as of December 31, 2004 based on the framework inInternal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of Pepco Holdings concluded that its internal control over financial reporting was effective as of December 31, 2004.

     Management's assessment of the effectiveness of its internal controls over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report which is included herein.

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Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors
of Pepco Holdings, Inc.:

We have completed an integrated audit of Pepco Holdings, Inc.'s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedules

In our opinion, the consolidated financial statements listed in the accompanying index, present fairly, in all material respects, the financial position of Pepco Holdings, Inc. and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2)present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conduct ed our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it accounts for financial instruments with characteristics of both liabilities and equity as of July 1, 2003 and variable interest entities as of December 31, 2003.

Internal control over financial reporting

Also, in our opinion, management's assessment, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established inInternal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established inInternal Control - Integrated Framework issued by the COSO. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of the Company's internal

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control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is 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 generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthoriz ed acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP
Washington, DC
March 16, 2005

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EARNINGS
For the Year Ended December 31,	2004	2003		2002
(Millions, except per share data)
Operating Revenue
Power Delivery	$4,375.9		$4,016.8	$2,519.6
Competitive Energy	2,756.0		3,137.3	1,676.9
Other	89.9		117.2	128.0
Total Operating Revenue	7,221.8		7,271.3	4,324.5
Operating Expenses
Fuel and purchased energy	4,258.7		4,625.0	2,538.4
Other services cost of sales	637.9		577.6	263.4
Other operation and maintenance	799.9		767.8	523.9
Depreciation and amortization	440.5		422.1	239.8
Other taxes	302.8		273.9	225.6
Deferred electric service costs	36.3		(7.0)	(12.2)
Impairment losses	-		64.3	-
Gain on sales of assets	(30.0)		(68.8)	-
Total Operating Expenses	6,446.1		6,654.9	3,778.9
Operating Income	775.7		616.4	545.6
Other Income (Expenses)
Interest and dividend income	9.4		17.1	22.3
Interest expense	(373.6)		(368.3)	(213.8)
Gain (Loss) from equity investments	14.4		(.9)	(9.7)
Impairment loss on equity investments	(11.2)		(102.6)	-
Other income	29.3		41.9	26.2
Other expenses	(9.3)		(16.2)	(15.4)
Total Other Expenses	(341.0)		(429.0)	(190.4)
Preferred Stock Dividend Requirements of Subsidiaries	2.8		13.9	20.6
Income Before Income Tax Expense	431.9		173.5	334.6
Income Tax Expense	173.2		65.9	124.1
Income Before Extraordinary Item	$  258.7		$  107.6	$  210.5
Extraordinary Item (net of taxes of $4.1 million   for the year ended December 31, 2003)	-		5.9	-
Net Income	$  258.7		$  113.5	$  210.5
Earnings Per Share of Common Stock
Basic Before Extraordinary Item	$   1.47		$    .63	$   1.61
Basic - Extraordinary Item	$      -		$    .03	$      -
Basic Earnings Per Share of Common Stock	$   1.47		$    .66	$   1.61
Diluted Before Extraordinary Item	$   1.47		$    .63	$   1.61
Diluted - Extraordinary Item	$      -		$    .03	$      -
Diluted Earnings Per Share of Common Stock	$   1.47		$    .66	$   1.61
The accompanying Notes are an integral part of these Consolidated Financial Statements.

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS
For the Year Ended December 31,	2004	2003	2002
(Millions of Dollars)
Net income	$258.7	$113.5	$210.5
Other comprehensive earnings (loss), net of taxes
Unrealized gains (losses) on commodity      derivatives designated as cash flow hedges:
Unrealized holding (losses) gains       arising during period	(20.9)	45.0	29.2
Less: reclassification adjustment for            gains included in net earnings	33.4	18.9	.6
Net unrealized (losses) gains on       commodity derivatives	(54.3)	26.1	28.6
Realized gains (losses) on Treasury lock	11.7	11.7	(102.4)
Unrealized gains (losses) on interest rate swap     agreements designated as cash flow hedges:
Unrealized holding (losses) gains arising       during period	(4.5)	3.4	(13.7)
Less: reclassification adjustment for losses            included in net earnings	(9.6)	(5.6)	(1.9)
Net unrealized gains (losses) on interest       rate swaps	5.1	9.0	(11.8)
Unrealized (losses) gains on marketable securities:
Unrealized holding (losses) gains arising       during period	(3.6)	6.1	5.7
Less: reclassification adjustment for gains            (losses) included in net earnings	0.8	0.3	(0.1)
Net unrealized (losses) gains on marketable       securities	(4.4)	5.8	5.8
Minimum pension liability adjustment	(6.9)	-	-
Other comprehensive (losses) earnings, before tax	(48.8)	52.6	(79.8)
Income tax (benefit) expense	(19.5)	22.4	(33.6)
Other comprehensive (losses) earnings, net of tax	(29.3)	30.2	(46.2)
Comprehensive earnings	$229.4	$143.7	$164.3
The accompanying Notes are an integral part of these Consolidated Financial Statements.

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
ASSETS	December 31,     2004	December 31,     2003
(Millions of Dollars)
CURRENT ASSETS
Cash and cash equivalents	$    29.6	$    90.6
Restricted cash	42.0	24.2
Marketable securities	-	23.0
Accounts receivable, less allowance for     uncollectible accounts of $43.7 million and     $43.5 million	1,104.0	1,059.9
Fuel, materials and supplies - at average cost	268.4	281.2
Unrealized derivative receivables	90.3	81.4
Prepaid expenses and other	119.6	125.0
Total Current Assets	1,653.9	1,685.3
INVESTMENTS AND OTHER ASSETS
Goodwill	1,430.5	1,432.3
Regulatory assets	1,335.4	1,435.2
Investment in financing trusts	-	2.9
Investment in finance leases held in Trust	1,218.7	1,143.1
Prepaid pension expense	165.7	166.6
Other	457.2	541.0
Total Investments and Other Assets	4,607.5	4,721.1
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	11,045.2	10,747.2
Accumulated depreciation	(3,957.2)	(3,782.3)
Net Property, Plant and Equipment	7,088.0	6,964.9
TOTAL ASSETS	$13,349.4	$13,371.3
The accompanying Notes are an integral part of these Consolidated Financial Statements.

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY	December 31,     2004	December 31,     2003
(Millions of Dollars, except share data)
CURRENT LIABILITIES
Short-term debt	$   836.0		$   903.3
Accounts payable and accrued liabilities	640.6		699.6
Debentures issued to Financing Trust	-		25.8
Capital lease obligations due within one year	4.9		4.4
Taxes accrued	59.8		130.4
Interest accrued	90.1		92.9
Other	311.4		323.3
Total Current Liabilities	1,942.8		2,179.7
DEFERRED CREDITS
Regulatory liabilities	391.9		426.7
Income taxes	1,981.8		1,688.7
Investment tax credits	55.7		63.7
Other post-retirement benefit obligations	279.5		276.9
Other	203.7		216.3
Total Deferred Credits	2,912.6		2,672.3
LONG-TERM LIABILITIES
Long-term debt	4,362.1		4,588.9
Transition Bonds issued by ACE Funding	523.3		551.3
Long-term project funding	65.3		68.6
Debentures issued to financing trusts	-		72.2
Mandatorily redeemable serial preferred stock of a subsidiary	-		45.0
Capital lease obligations	122.1		126.8
Total Long-Term Liabilities	5,072.8		5,452.8
COMMITMENTS AND CONTINGENCIES (NOTE 12)
PREFERRED STOCK OF SUBSIDIARIES
Serial preferred stock	27.0		35.3
Redeemable serial preferred stock	27.9		27.9
Total preferred stock	54.9		63.2
SHAREHOLDERS' EQUITY
Common stock, $.01 par value, - authorized 400,000,000 shares -     issued 188,327,510 shares and 171,769,448 shares, respectively	1.9		1.7
Premium on stock and other capital contributions	2,566.2		2,246.6
Capital stock expense	(13.5)		(3.3)
Accumulated other comprehensive loss	(52.0)		(22.7)
Retained income	863.7		781.0
Total Shareholders' Equity	3,366.3		3,003.3
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$13,349.4		$13,371.3
The accompanying Notes are an integral part of these Consolidated Financial Statements

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Year Ended December 31,		2004		2003		2002
(Millions of Dollars)
OPERATING ACTIVITIES
Net income		$	258.7	$	113.5	$	210.5
Adjustments to reconcile net income to net cash   from (used by) operating activities:
Depreciation and amortization			440.5		422.1		239.8
Gain on sale of assets			(30.0)		(68.8)		-
Undistributed (gains) losses from affiliates			-		8.4		(1.3	)
Derivative activity			(59.6)		45.6		11.1
Extraordinary item			-		(10.0)		-
Rents received from leveraged leases under income earned			(76.4)		(72.4)		(35.9	)
Impairment losses			11.2		166.9		-
Deferred income taxes			217.5		199.0		261.1
Investment tax credit adjustments			(8.0)		(5.3)		(2.4	)
Changes in:
Accounts receivable			(172.4)		43.2		(67.8	)
Regulatory assets and liabilities			(11.8)		(75.6)		27.4
Prepaid expenses			20.2		(23.3)		74.1
Other deferred charges			13.9		54.8		(44.6	)
Other deferred credits			35.9		(55.5)		4.4
Energy contracts			(12.3)		(21.6)		(7.4	)
Prepaid pension costs			0.9		(17.3)		3.1
Materials and supplies			12.9		(18.0)		(35.7	)
Accounts payable and accrued payroll			134.0		(65.4)		179.2
Interest and taxes accrued			(40.6)		41.1		(22.5	)
Net Cash From Operating Activities			734.6		661.4		793.1
INVESTING ACTIVITIES
Acquisition of Conectiv, net of cash acquired			-		-		(1,075.6	)
Net investment in property, plant and equipment			(517.4)		(598.2)		(503.8	)
Proceeds from/changes in:	��
Sale of office building and other properties			46.4		147.7		4.0
Sale of Starpower investment			29.0		-		-
Proceeds from combustion turbine contract cancellation			-		52.0		-
Purchase of leveraged leases			-		-		(319.6	)
Proceeds from sale of marketable securities			117.6		715.2		27.0
Purchase of marketable securities			(98.2)		(558.6)		(34.0	)
Purchases of other investments			(0.3)		(11.0)		(22.5	)
Proceeds from sale of other investments			15.1		11.5		15.2
Net investment in receivables			2.9		(43.2)		(7.5	)
Changes in restricted cash			(17.8)		31.0		(37.0	)
Net other investing activities			.6		(1.2)		(11.1	)
Net Cash Used By Investing Activities			(422.1)		(254.8)		(1,964.9	)
FINANCING ACTIVITIES
Dividends paid on preferred stock of subsidiaries			(2.8)		(4.6)		(5.9	)
Dividends paid on common stock			(176.0)		(170.7)		(130.6	)
Common stock issued to the Dividend Reinvestment Plan			29.2		31.2		12.4
Redemption of debentures issued to financing trust			(95.0)		-		-
Redemption of Trust Preferred Stock of subsidiaries			-		(195.0)			-
Redemption of preferred stock of subsidiaries			(53.3)		(2.5)		(9.9	)
Issuance of common stock			288.8		1.6		105.7
Reacquisition of the Company's common stock			-		-		(2.2	)
Issuances of long-term debt			650.4		1,136.9		1,981.7
Redemption of long-term debt			(1,119.7)		(692.2)		(415.2	)
Issuances (repayments) of short-term debt, net			136.3		(452.7)		(684.8	)
Cost of issuances and financings			(26.7)		(14.6)		(130.4	)
Net other financing activities			(4.7)		(5.3)		(2.7	)
Net Cash (Used By) From Financing Activities			(373.5)		(367.9)		718.1
Net (Decrease) Increase In Cash and Cash Equivalents			(61.0)		38.7		(453.7	)
Cash and Cash Equivalents at Beginning of Year			90.6		51.9		505.6
CASH AND CASH EQUIVALENTS AT END OF YEAR		$	29.6	$	90.6	$	51.9
Supplemental Disclosure of Cash Flow Information
Cash paid for interest (net of capitalized   interest of $2.9 million, $11.3 million and $10.6   million) and (received)for income taxes:
Interest		$	356.9	$	390.3	$	139.6
Income taxes		$	(19.9)	$	(144.1)	$	(271.0	)
The accompanying Notes are an integral part of these Consolidated Financial Statements.

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
	Common Stock            Shares      Par Value				Premium on Stock			Capital Stock Expense	Accumulated Other Comprehensive (Loss) Income			Retained Income
(Dollar Amounts in Millions)
BALANCE, DECEMBER 31, 2001	118,544,883		$118.5		$	1,028.3		$(12.9)		$ (6.7	)		$974.1
Net Income	-		-			-		-		-			210.5
Other comprehensive loss	-		-			-		-		(46.2	)		-
Dividends on common stock   ($1.00/sh.)	-		-			-		-		-			(130.6	)
Issuance of common stock:
Related to Conectiv     acquisition	163,602,584		1.7			2,095.6		(2.1)		-			-
Original issue shares	5,750,000		-			105.7		-		-			-
DRP original shares	629,777		-			12.4		-		-			-
Cancellation of Pepco    outstanding stock	(107,221,176	)	(107.2	)		(963.8	)	10.7		-			-
Cancellation of Pepco   Treasury Stock	(11,323,707	)	(11.3	)		(64.5	)	1.1		-			(215.8	)
Reacquired Conectiv and   Pepco PARS	-		-			(3.2	)	-		-			-
Vested options converted to   Pepco Holdings options	-		-			1.5		-		-			-
BALANCE, DECEMBER 31, 2002	169,982,361		$1.7		$	2,212.0		$ (3.2)		$(52.9	)		$838.2
Net Income	-		-			-		-		-			113.5
Other comprehensive income	-		-			-		-		30.2			-
Dividends on common stock   ($1.00/sh.)	-		-			-		-		-			(170.7	)
Issuance of common stock:
Original issue shares	80,665		-			1.6		-		-			-
DRP original shares	1,706,422		-			31.2		-		-			-
Release of restricted stock	-		-			.1		(.1)		-			-
Reacquired Conectiv and   Pepco PARS	-		-			1.7		-		-			-
BALANCE, DECEMBER 31, 2003	171,769,448		$  1.7		$2,246.6			$ (3.3)		$   (22.7	)		$781.0
Net Income	-		-			-		-					258.7
Other comprehensive loss	-		-			-		-		(29.3	)
Dividends on common stock   ($1.00/sh.)	-		-			-		-		-			(176.0	)
Reacquisition of subsidiary   preferred stock	-		-			1.0		-		-			-
Issuance of common stock:
Original issue shares	15,086,126		.2			288.6		(10.2)		-			-
DRP original shares	1,471,936		-			29.2		-		-			-
Reacquired Conectiv and   Pepco PARS	-		-			.6		-		-			-
Vested options converted to   Pepco Holdings options	-		-			.2		-		-			-
BALANCE, DECEMBER 31, 2004	188,327,510		$  1.9		$	2,566.2		$(13.5)		(52.0	)		$863.7
The accompanying Notes are an integral part of these Consolidated Financial Statements.

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NOTES TO 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 three principal areas of business operations:

· regulated electricity and natural gas delivery,

· competitive energy generation, marketing and supply, and

· other activities consisting primarily of investments in energy-related assets.

     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 areas of operation.

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 subsidiaries Pepco, DPL and ACE, each of which is a regulated public utility in the jurisdictions in which it serves customers. DPL and ACE

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conduct their power delivery operations under the tradename Conectiv Power Delivery.

Competitive Energy

     PHI's competitive energy business provides competitive generation, marketing and supply of electricity and gas, and related energy management services, 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 and its subsidiaries (collectively, Pepco Energy Services).

Other Non-Regulated

     This component of PHI's business is conducted through itssubsidiary Potomac Capital Investment Corporation (PCI), which manages a portfolio of financial investments, consisting primarily of energy leveraged leases. In 2003, PCI discontinued making new investments. PHI's subsidiary Pepco Communications, Inc. (Pepcom) ceased operations in December 2004 following the sale of its principal asset, a 50% interest in Starpower Communications, LLC (Starpower) for $29 million in cash.

     For financial information relating to PHI's segments, see Note (3) Segment Information to the consolidated financial statements of PHI set forth in Item 8 of this Form 10-K. This segment information includes a revision of PHI's segments for 2003 and 2002 to reflect that, as of January 1, 2004, the formerly separate segments of Pepco Power Delivery and Conectiv Power Delivery were combined to form one segment.

(2)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation Policy

     The accompanying consolidated financial statements include the accounts of Pepco Holdings and its wholly owned subsidiaries. All intercompany balances and transactions between subsidiaries have been eliminated. Pepco Holdings uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies in which it holds a 20% to 50% voting interest and cannot exercise control over the operations and policies of the investment. Under the equity method, Pepco Holdings records its interest in the entity as an investment in the accompanying Consolidated Balance Sheets, and its percentage share of the entity's earnings are recorded in the accompanying Consolidated Statements of Earnings. Additionally, the proportionate interests in jointly owned electric plants are consolidated.

     In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46) issued in January 2003, and with the FASB Interpretation No. 46-R "Consolidation of Variable Interest Entities" (FIN 46R) issued in December 2003, Pepco Holdings deconsolidated several entities that had previously been consolidated and consolidated several small entities that had not previously been consolidated. FIN 46 and FIN 46R address conditions under which an entity should be consolidated based upon variable interests rather than voting interests. For additional information regarding the impact of implementing FIN 46 and FIN 46R, refer to the FIN 46 discussion later in this Note.

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Composition of Consolidated Financial Statements

     The accompanying consolidated statements of earnings, consolidated statements of comprehensive earnings, and consolidated statements of cash flows for the years ended December 31, 2004 and 2003 include Pepco Holdings and its subsidiaries' results for the full year. These statements for the year ended December 31, 2002 include Pepco and its pre-merger subsidiaries' results for the entire year consolidated with Conectiv and its subsidiaries operating results starting on August 1, 2002, the date the acquisition of Conectiv was consummated. Accordingly, the statements referred to above for the years ended December 31, 2004 and 2003 are not comparable with those for the year ended December 31, 2002. However, the amounts included in the accompanying consolidated balance sheets and consolidated statements of shareholders' equity for the years ended December 31, 2004 and 2003 are comparable since both years reflect the accounting impact of the merger transaction.

Use of Estimates

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America, such as Statement of Position 94-6 "Disclosure of Certain Significant Risks and Uncertainties," requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Examples of significant estimates used by Pepco Holdings include the assessment of contingencies and the need/amount for reserves of future receipts from Mirant (refer to the "Relationship with Mirant" section, herein), the calculation of future cash flows and fair value amounts for use in goodwill and asset impairment evaluations, fair value calculations (based on estimating market pricing) associated with derivative instruments, pension and other post-re tirement benefits assumptions, unbilled revenue calculations, and judgment involved with assessing the probability of recovery of regulatory assets. Additionally, PHI is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of our business. We record an estimated liability for these proceedings and claims based upon the probable and reasonably estimatable criteria contained in SFAS No. 5 "Accounting for Contingencies." Although Pepco Holdings believes that its estimates and assumptions are reasonable, they are based upon information presently available. Actual results may differ significantly from these estimates.

Regulation of Power Delivery Operations

     The power delivery operations of Pepco are regulated by the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC).

     The power delivery operations of DPL are regulated by the Delaware Public Service Commission (DPSC), the MPSC, and the Virginia State Corporation Commission (VSCC).

     The power delivery operations of ACE are regulated by the New Jersey Board of Public Utilities (NJBPU).

     The wholesale power delivery operations of each of Pepco, DPL, and ACE are regulated by the Federal Energy Regulatory Commission (FERC).

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     The requirements of SFAS No. 71 apply to the power delivery businesses of Pepco, DPL, and ACE. SFAS No. 71 allows regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities and to defer the income statement impact of certain costs that are expected to be recovered in future rates. Management's assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders, and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, then the regulatory asset would be eliminated through a charge to earnings.

     The components of Pepco Holdings' regulatory asset balances at December 31, 2004 and 2003, are as follows:

	2004	2003
	(Millions of Dollars)
Securitized stranded costs	$  887.7	$  945.4
Deferred energy supply costs	111.1	147.1
Deferred recoverable income taxes	162.2	189.5
Deferred debt extinguishment costs	78.3	70.2
Unrecovered purchased power contracts	22.6	26.3
Deferred other post-retirement benefit costs	20.0	22.5
Other	53.5	34.2
Total regulatory assets	$1,335.4	$1,435.2

     The components of Pepco Holdings' regulatory liability balances at December 31, 2004 and 2003, are as follows:

	2004	2003
	(Millions of Dollars)
Deferred income taxes due to customers	$ 71.0	$ 74.9
Regulatory liability for Federal and   New Jersey tax benefit	40.7	42.2
Generation Procurement Credit, customer sharing   commitment and other	26.1	51.7
Removal costs	254.1	257.9
Total regulatory liabilities	$391.9	$426.7

     A description of the regulatory assets and regulatory liabilities is as follows:

     Securitized Stranded Costs: Represents stranded costs associated with a non-utility generator (NUG) contract termination payment and the discontinuation of the application of SFAS No. 71 for ACE's electricity generation business. The recovery of these stranded costs has been securitized through the issuance of Transition Bonds by Atlantic City Electric Transition Funding LLC (ACE Funding). A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. Costs are amortized over the life of the Transition Bonds, which mature between 2010 and 2023.

     Deferred Energy Supply Costs:Primarily represents deferred costs relating to the provision of Basic Generation Service (BGS) and other restructuring related costs incurred by ACE. Also includes deferred fuel costs for DPL's gas business. All deferrals receive a return. ACE deferrals

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are recoverable over the next 9 years. DPL's deferred fuel costs are recovered annually.

     Deferred Recoverable Income Taxes:Represents deferred income tax assets recognized from the normalization of flow-through items as a result of amounts previously provided to customers. As temporary differences between the financial statement and tax basis of assets reverse, deferred recoverable income taxes are amortized. There is no return on these deferrals.

     Deferred Debt Extinguishment Costs:Represents the costs of debt extinguishment for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period. A return is received on these deferrals.

     Unrecovered Purchased Power Contracts: Represents deferred costs related to purchase power contracts at ACE and DPL which are being recovered over 3 and 9 years and earn a return.

     Deferred Other Post-retirement Benefit Costs:Represents the non-cash portion of other post-retirement benefit costs deferred by ACE during 1993 through 1997. This cost is being recovered over a 15-year period that began on January 1, 1998. There is no return on this deferral.

     Other:  Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years and generally do not receive a return.

     Deferred Income Taxes Due to Customers: Represents the portion of deferred income tax liabilities applicable to utility operations of Pepco, DPL, and ACE that has not been reflected in current customer rates for which future payment to customers is probable. As temporary differences between the financial statement and tax basis of assets reverse, deferred recoverable income taxes are amortized.

     Regulatory Liability for Federal and New Jersey Tax Benefit:Securitized stranded costs include a portion of stranded costs attributable to the future tax benefit expected to be realized when the higher tax basis of the generating plants is deducted for New Jersey state income tax purposes as well as the future benefit to be realized through the reversal of federal excess deferred taxes. To account for the possibility that these tax benefits may be given to ACE's regulated electricity delivery customers through lower rates in the future, ACE established a regulatory liability. The regulatory liability related to federal excess deferred taxes will remain until such time as the Internal Revenue Service issues its final regulations with respect to normalization of these federal excess deferred taxes.

     Generation Procurement Credit (GPC), Customer Sharing Commitment, and Other:GPC represents the customers' share of profits that Pepco has realized on the procurement and resale of generation services to standard offer service customers that has not yet been distributed to customers. Pepco is currently distributing the customers' share of profits monthly to customers in a billing credit. Pepco's settlement agreements related to its December 2000 generation divestiture, approved by both the DCPSC and MPSC, required the sharing between customers and shareholders of any profits earned during the four-year transition period in each jurisdiction.

     Removal Costs:  Represents Pepco's and DPL's asset retirement obligations associated with removal costs accrued using Commission approved depreciation rates for transmission, distribution, and general utility

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property. In accordance with SFAS 143, accruals for removal costs were classified as a regulatory liability.

Revenue Recognition

Regulated Revenue

     The power delivery businesses recognize revenues for the supply and delivery of electricity and gas upon delivery to the customer, including amounts for services rendered but not yet billed. Pepco Holdings recorded amounts for unbilled revenue of $226.7 million and $184.6 million as of December 31, 2004 and 2003, respectively. These amounts are included in the "accounts receivable" line item in the accompanying consolidated balance sheets.

     Additionally, the collection of taxes related to the consumption of electricity and gas by its customers, such as fuel, energy, or other similar taxes are components of the Company's tariffs and as such, are billed to customers and recorded in Operating Revenues. Payments of these taxes by the Company are recorded in Other Taxes. Excise tax related generally to the consumption of gasoline by the Company in the normal course of business is charged to operations, maintenance or construction, and is de minimis.

Competitive Revenue

     The competitive energy businesses recognize revenues for the supply and delivery of electricity and gas upon delivery to the customer, including amounts for services rendered, but not yet billed. Conectiv Energy recognizes revenue when delivery is complete. Unrealized derivative gains and losses are recognized in current earnings as revenue if the derivative activity does not qualify for hedge accounting or normal sales treatment under SFAS No. 133. Pepco Energy Services recognizes revenue for its wholesale and retail commodity business upon delivery to customers. Revenues for Pepco Energy Services' energy efficiency construction business are recognized using the percentage-of-completion method of revenue recognition which recognizes revenue as work is completed on the contract, and revenues from its operation and maintenance and other products and services contracts are recognized when earned. Revenues from the other non-regulated business l ines are principally recognized when services are performed or products are delivered; however, revenues from utility industry services contracts are recognized using the percentage-of-completion method of revenue recognition.

Transition Power Agreement and Generation Procurement Credit

     As part of the agreement to divest its generation assets, Pepco entered into separate Transition Power Agreements (TPAs) with Mirant for the District of Columbia and Maryland. In connection with Mirant's bankruptcy proceeding, the TPAs were amended by the Amended Settlement Agreement and Release dated as of October 24, 2003 (Settlement Agreement). For information regarding the impact of Mirant's bankruptcy on Pepco's operations, refer to the Note (12) Commitments and Contingencies, "Relationship with Mirant Corporation" section, herein.

Accounting For Derivatives

     Pepco Holdings and its subsidiaries use derivative instruments primarily to manage risk associated with commodity prices and interest rates. Risk management policies are determined by PHI's Corporate Risk Management Committee (CRMC). The CRMC monitors interest rate fluctuation, commodity price fluctuation, and credit risk exposure. The CRMC sets risk management

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policies that establish limits on unhedged risk and determine risk reporting requirements.

     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. SFAS 133 requires derivative instruments to be measured at fair value. Derivatives are recorded on the balance sheet as other assets or other liabilities with offsetting gains and losses flowing through earnings unless they are designated as cash flow hedges. Derivatives can be accounted for in four ways: (i) marked-to-market through current earnings, (ii) cash flow hedge accounting, (iii) fair value hedge accounting, and (iv) normal purchase and sales accounting.

     Mark-to-market gains and losses on derivatives that are not designated as hedges are presented on the Consolidated Statements of Earnings as operating revenue. PHI uses mark-to-market accounting through earnings for derivatives that either do not qualify for hedge accounting, or that Management chooses not to designate as hedges. Derivatives that were used for proprietary trading were marked-to-market through earnings.

     The gain or loss on a derivative that hedges exposure to variable cash flow of a forecasted transaction is initially recorded in other comprehensive income (a separate component of common stockholders' equity) and is subsequently reclassified into earnings in the same category as the item being hedged when the forecasted transaction occurs. If a forecasted transaction is no longer probable, the deferred gain or loss in accumulated other comprehensive income is immediately reclassified to earnings. Any ineffective portion of the cash flow hedge is also recognized in earnings immediately.

     Changes in the fair value of other hedging derivatives, designated as fair value hedges, result in a change in the value of the asset, liability, or firm commitment being hedged. Changes in fair value of the asset, liability, or firm commitment, and the hedging instrument, are recorded in the consolidated statements of earnings.

     Certain commodity forwards are not required to be recorded on a mark-to-market basis of accounting as provided under the guidance of SFAS No. 133. These contracts are designated as "normal purchases and sales" as permitted by SFAS No. 133. The contracts are used in the company's normal operations, typically settle physically, and follow standard accrual accounting. Unrealized gains and losses on these contracts do not appear on PHI's Consolidated Balance Sheets. Examples of these transactions include fuel to be consumed in power plants and actual receipts and deliveries of electric power. Normal purchases and sales transactions are presented on a gross basis, normal sales as operating revenue, and normal purchases as fuel and purchased energy.

     PHI uses option contracts to mitigate certain risk factors. These options are normally marked-to-market through current earnings because of the difficulty in qualifying options for hedge accounting treatment. Option premiums are deferred as prepaid expenses or other liabilities until the exercise period of the option is realized. Market prices are used when available. If market prices are not available, the market value of the options is estimated using Black-Scholes closed form models and is included in earnings. Option contracts typically make up only a small portion of PHI's total portfolio.

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     The fair value of derivatives is determined using quoted exchange prices where available. For instruments that are not traded on an exchange, external broker quotes are used to determine fair value. For some custom and complex instruments, an internal model is used to interpolate broker quality price information. Models are also used to estimate volumes for certain transactions. The same valuation methods are used to determine the value of non-derivative, commodity exposure for risk management purposes.

     Derivatives that are marked-to-market through current earnings, the ineffective portion of cash flow hedges, and the portion of fair value hedges that flows to current earnings are presented in net on the Consolidated Statement of Earnings. When a hedging gain or loss is realized, it is presented net in the same category as the underlying item being hedged. Normal purchase and sales transactions are presented gross on the Consolidated Statement of Earnings as they are realized. The unrealized assets and liabilities that offset unrealized derivative gains and losses are presented gross on the Consolidated Balance Sheets except where contractual netting agreements are in place.

     As of March 2003, Conectiv Energy ceased all proprietary trading activities, which generally consisted of the entry into contracts to take a view of market direction, capture market price change, and put capital at risk.

     Conectiv Energy engages in commodity hedging activities to minimize the risk of market fluctuations associated with the purchase and sale of energy commodities (natural gas, petroleum, coal and electricity). The majority of these hedges relate to the procurement of fuel for its power plants, fixing the cash flows from the plant output, and securing power for electric load service. Conectiv Energy's hedging activities are conducted using derivative instruments, including forward contracts, swaps and futures, designated as cash flow hedges, which are designed to reduce the variability in future cash flows. Conectiv Energy's commodity hedging objectives, in accordance with its risk management policy, are primarily the assurance of stable and known cash flows and the fixing of favorable prices and margins when they become available.

     Conectiv Energy assesses risk on a total portfolio basis and by component (e.g. Generation Output, Generation Fuel, Load Supply, etc.). Portfolio risk combines the generation fleet, load obligations, miscellaneous commodity sales and hedges. Accounting hedges are matched against each component using the product or products that most closely represents the underlying hedged item. The total portfolio is risk managed based on its net megawatt position by month. If the total portfolio becomes too long or too short for a period, steps are taken to reduce or increase hedges. Total portfolio-level hedging includes accounting hedges (derivatives designated as cash flow hedges), derivatives that are being marked-to-market through earnings, and other physical commodity purchases and sales.

     DPL uses derivative instruments (forward contracts, futures, swaps, and exchange-traded and over-the-counter options) primarily to reduce gas commodity price volatility while limiting its firm customers' exposure to increases in the market price of gas. DPL also manages commodity risk with physical natural gas and capacity contracts that do not meet the definition of derivatives. The primary goal of these activities is to reduce the exposure of its regulated retail gas customers to natural gas price spikes. All premiums paid and other transaction costs incurred as part of DPL's natural gas hedging activity in addition to all gains and losses are fully recoverable through the fuel adjustment clause approved by the DPSC and are deferred under SFAS No. 71 until recovered. At December 31, 2004 there was a

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deferred derivative liability on DPL's balance sheet of $1.5 million, and an inventory contra-asset balance of $1.1 million, offset by a $2.6 million regulatory asset.

     Pepco Energy Services purchases natural gas futures and natural gas and electricity forward contracts to hedge price risk in connection with the purchase of physical natural gas and electricity for delivery to customers in future months. Pepco Energy Services accounts for its natural gas futures contracts as cash flow hedges of forecasted transactions. Its natural gas and electricity forward contracts are accounted for under standard accrual accounting as these contracts are exempted under SFAS No. 133 because they are used in the company's normal operations.

     Conectiv Bethlehem, LLC (CBI), a subsidiary of Conectiv Energy, entered into an interest rate swap agreement for the purpose of managing its overall borrowing rate and limiting its interest rate risk associated with debt it has incurred. CBI hedged 75% of the interest rate payments for its variable rate debt. CBI formally designated its interest rate swap agreements as a cash flow hedge. CBI repaid all of its external debt and settled its interest rate swap agreement ($6.8 million) in September 2004.

     PCI has entered into interest rate swap agreements for the purpose of managing its overall borrowing rate and limiting its interest rate risk associated with debt it has issued. PCI currently hedges 100% of its variable rate debt and approximately 55% of its fixed rate debt for its Medium Term Note program. PCI formally designated its interest rate swap agreements as both cash flow hedge and fair value hedge instruments, as appropriate.

EITF 03-11

     On January 1, 2004, Pepco Holdings implemented EITF Issue No. 03-11 (EITF 03-11), "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, 'Accounting for Derivative Instruments and Hedging Activities,' and not 'Held for Trading Purposes' as Defined in EITF Issue No. 02-3, 'Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.'" As a result of the implementation of this EITF, $219.1 million of operating revenues and operating expenses related to certain Conectiv Energy and Pepco Energy Services energy contracts are reported on a net basis in the accompanying consolidated statements of earnings for the year ended December 31, 2004, as these energy contracts did not physically settle. Had EITF 03-11 been effective for the year ended December 31, 2003, Pepco Holdings' operating revenues a nd operating expenses would have been reduced by $291.8 million. The implementation of EITF 03-11 did not have an impact on Pepco Holdings' financial condition, net earnings or cash flows.

Accounting For Marketable Securities

     PCI's investment activity, which prior to 2004 consisted of preferred stock investments with mandatorily redeemable features and marketable equity securities has decreased since Pepco Holdings announced the discontinuation of further new investment activity by PCI. Under the specific identification method, PCI realized gross gains of $1.0 million, $.9 million, and $.6 million, respectively, on sales or calls of securities for the years ended December 31, 2004, 2003 and 2002. In addition, PCI recorded gross losses of $.2 million, $.6 million, and $.7 million, respectively, on sales or calls of securities for the years ended December 31, 2004, 2003 and 2002.

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     Included in net unrealized gains/losses at December 31, 2003, are gross unrealized losses of zero and gross unrealized gains of $4.5 million.

     In April 2004, PCI received a cash dividend (including dividends in arrears) of $3.8 million from its remaining preferred stock investment and recorded an after-tax gain of approximately $3.1 million. The remaining preferred shares were also sold in April resulting in an after-tax gain of approximately $.4 million.

Accounting for Goodwill

     Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. The accounting for goodwill is governed by SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." Pepco Holdings' goodwill balance that was generated from Pepco's acquisition of Conectiv has been allocated to its Power Delivery business. SFAS No. 141 requires business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting and broadens the criteria for recording intangible assets apart from goodwill. SFAS No. 142 requires that purchased goodwill and certain indefinite-lived intangibles no longer be amortized, but instead be tested for impairment. Substantially all of Pepco Holdings' goodwill was generated by the acquisition of Conectiv by Pepco that closed in 2002.

Goodwill Impairment Evaluation

     The provisions of SFAS No. 142 require the evaluation of goodwill for impairment at least annually or more frequently if events and circumstances indicate that the asset might be impaired. Examples of such events and circumstances include an adverse action or assessment by a regulator, a significant adverse change in legal factors or in the business climate, and unanticipated competition. SFAS No. 142 indicates that if the fair value of a reporting unit is less than its carrying value, including goodwill, an impairment charge may be necessary. During 2004 Pepco Holdings tested its goodwill for impairment as of July 1, 2004. This testing indicated that none of Pepco Holdings' goodwill balance was impaired.

Long Lived Assets Impairment Evaluation

     Pepco Holdings is required to evaluate certain long-lived assets (for example, generating property and equipment and real estate) to determine if they are impaired when certain conditions exist. SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets," governs the accounting treatment for impairments of long-lived assets and indicates that companies are required to test long-lived assets for recoverability whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition.

     For long-lived assets that are expected to be held and used, SFAS No. 144 requires that an impairment loss shall only be recognized if the carrying amount of an asset is not recoverable and exceeds its fair value. For long-lived assets that can be classified as assets to be disposed of by sale under SFAS No. 144, an impairment loss shall be recognized to the extent their carrying amount exceeds their fair value including costs to sell.

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     During 2003 PHI recorded an impairment charge of $53.3 million from the cancellation of a CT contract and an $11.0 million aircraft impairment.

Pro Forma Information (unaudited)

     Since the purchase method was used to account for the August 1, 2002 purchase of Conectiv by Pepco, the accompanying consolidated financial results include Conectiv and its pre-merger subsidiaries' operating results commencing on August 1, 2002. Accordingly, Pepco Holdings' consolidated operating results for the year ended December 31, 2002 are not comparable with the corresponding 2004 and 2003 results.

     The following pro forma unaudited financial information for Pepco Holdings on a consolidated basis gives effect to the merger as if it had occurred at the beginning of 2002. This information does not reflect future revenues or cost savings that may result from the acquisition and is not indicative of actual results of operations had the acquisition occurred at the beginning of 2002 or of results that may occur in the future. Amounts, except earnings per share, are in millions.

	For the Year Ended   December 31, 2002
Operating Revenue		$6,777.3
Net Income		$  231.5
Basic and Diluted Earnings Per Share of common stock		$   1.42

     The primary pro forma adjustments in determining pro forma earnings per share were related to interest expense incurred on acquisition debt and interest income on existing funds used to partially fund the acquisition. Pro forma basic and diluted weighted average shares outstanding at December 31, 2002 were 163.4 million.

Cash and Cash Equivalents

     Cash and cash equivalents include cash on hand, money market funds, and commercial paper with original maturities of three months or less.

Restricted Cash

     Restricted cash represents cash either held as collateral or pledged as collateral and is restricted from use for general corporate purposes.

Prepaid Expenses and Other

     The prepaid expenses and other balance primarily consists of prepayments, deferred income tax assets, and deferred income tax net operating losses.

Accounts Receivable and Allowance for Uncollectible Accounts

     Pepco Holdings' subsidiaries' accounts receivable balances primarily consist of customer accounts receivable, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date, usually within one month. PHI uses the allowance method to account for uncollectible accounts receivable.

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Capitalized Interest and Allowance for Funds Used During Construction

     In accordance with the provisions of SFAS No. 34, "Capitalization of Interest Cost," the cost of financing the construction of Pepco Holdings' non-regulated subsidiaries electric generating plants is capitalized. Other non-utility construction projects also include financing costs in accordance with SFAS No. 34. The cost of additions to, and replacements or betterments of, retirement units of property and plant is capitalized for PHI's regulated businesses. Such costs include material, labor, the capitalization of an Allowance for Funds Used During Construction (AFUDC) and applicable indirect costs, including engineering, supervision, payroll taxes and employee benefits.

     Pepco Holdings recorded AFUDC for borrowed funds of $2.8 million, $3.0 million, and $3.4 million for the years ended December 31, 2004, 2003, and 2002, respectively. These amounts are recorded as a reduction of "interest expense" in the accompanying consolidated statements of earnings.

     Pepco Holdings recorded amounts for AFUDC for equity income of $4.1 million, $4.6 million and $3.0 million for the years ended December 31, 2004, 2003 and 2002, respectively. The amounts are included in the "other income" caption of the accompanying consolidated statements of earnings.

Leasing Activities

     Pepco Holdings accounts for leases entered into by its subsidiaries in accordance with the provisions of SFAS No. 13, "Accounting for Leases." Income from investments in direct financing leases and leveraged lease transactions, in which PCI is an equity participant, is accounted for using the financing method. In accordance with the financing method, investments in leased property are recorded as a receivable from the lessee to be recovered through the collection of future rentals. For direct financing leases, unearned income is amortized to income over the lease term at a constant rate of return on the net investment. Income, including investment tax credits, on leveraged equipment leases is recognized over the life of the lease at a constant rate of return on the positive net investment. Investments in equipment under capital leases are stated at cost, less accumulated depreciation. Depreciation is recorded on a straight-line basis over the equipment's estimated useful life.

Amortization of Debt Issuance and Reacquisition Costs

     Expenses incurred in connection with the issuance of long-term debt, including premiums and discounts associated with such debt, are deferred and amortized over the lives of the respective debt issues. Costs associated with the reacquisition of debt for PHI's regulated operations are also deferred and amortized over the lives of the new issues.

Pension and Other Post Retirement Benefit Plans

     Pepco Holdings sponsors a retirement plan that covers substantially all employees of Pepco, Conectiv and certain employees of other Pepco Holdings' subsidiaries (Retirement Plan). Following the consummation of the acquisition of Conectiv by Pepco on August 1, 2002, the Pepco General Retirement Plan and the Conectiv Retirement Plan were merged into the Retirement Plan on December 31, 2002. The provisions and benefits of the merged Retirement Plan for Pepco employees are identical to those of the original Pepco plan and for Conectiv employees the provisions and benefits of the merged Retirement Plan are identical to the original Conectiv plan. Pepco Holdings also provides supplemental retirement benefits to certain

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eligible executive and key employees through nonqualified retirement plans. In addition to sponsoring non-contributory retirement plans, Pepco Holdings provides certain post-retirement health care and life insurance benefits for eligible retired employees.

     Pepco Holdings accounts for the Retirement Plan in accordance with SFAS No. 87, "Employers' Accounting for Pensions" and its post-retirement health care and life insurance benefits for eligible employees in accordance with SFAS No. 106, "Employers' Accounting for Post-retirement Benefits Other Than Pensions." PHI's financial statement disclosures are prepared in accordance with SFAS No. 132, "Employers' Disclosures about Pensions and Other Post-retirement Benefits," as revised.

Severance Costs

     In November 2004, PHI announced that its Power Delivery business planned to reduce its 4,200 employee work force by approximately 2% to 3% by the end of 2004. This work force reduction was accomplished through a combination of retirements and targeted reductions. This plan met the criteria for the accounting treatment provided under SFAS No. 88 "Employer's Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits" and SFAS No. 146 "Accounting for Costs Associated with Exit or Disposal Activities," as applicable. Additionally, during 2002, Pepco Holdings' management approved initiatives by Pepco and Conectiv to streamline its operating structure by reducing the number of employees at each company. These initiatives met the criteria for the accounting treatment provided under EITF No. 94-3 "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exi t an Activity (including Certain Costs Incurred in a Restructuring)." A roll forward of the severance accrual balance is as follows. (Amounts in millions)

Balance, December 31, 2002	$ 23.2
Accrued during 2003	-
Payments during 2003	(15.3)
Balance, December 31, 2003	$  7.9
Accrued during 2004	13.4
Payments during 2004	(12.5)
Balance, December 31, 2004	$  8.8

     Based on the number of employees that have accepted or are expected to accept the severance packages, substantially all of the severance liability related to the 2002 plan will be paid through mid 2005. Employees have the option of taking severance payments in a lump sum or over a period of time.

Property, Plant and Equipment

     Property, plant and equipment are recorded at cost. The carrying value of property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable under the provisions of SFAS No. 144. Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation. For non regulated property, the cost and accumulated depreciation of the property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of any gain or loss on disposition. For additional information regarding the treatment of removal obligations, refer to the "Asset Retirement Obligations" section included in this Note to the consolidated financial statements.

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     The annual provision for depreciation on electric and gas property, plant and equipment is computed on the straight-line basis using composite rates by classes of depreciable property. Accumulated depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. Property, plant and equipment other than electric and gas facilities is generally depreciated on a straight-line basis over the useful lives of the assets.

Asset Retirement Obligations

     Pepco Holdings adopted Financial Accounting Standards Board (FASB) Statement No. 143 entitled "Accounting for Asset Retirement Obligations" (SFAS No. 143) on January 1, 2003. This statement establishes the accounting and reporting standards for measuring and recording asset retirement obligations. Based on the implementation of SFAS No. 143, at December 31, 2004 and 2003, respectively, $254.1 million in costs of removal ($176.9 million for DPL and $77.2 million for Pepco) and $257.9 million in costs of removal ($181.5 million for DPL and $76.4 million for Pepco) have been reclassified as a regulatory liability in the accompanying consolidated balance sheets.

Stock-Based Compensation

     Pepco Holdings accounts for its stock-based employee compensation under the intrinsic value method of expense recognition and measurement prescribed by APB Opinion No. 25, "Accounting for Stock Issued to Employees, and related Interpretations" (collectively, APB No. 25). As required by FASB Statement No. 123, "Accounting for Stock-Based Compensation" (SFAS No. 123), as amended by FASB Statement No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," a tabular presentation of the pro-forma stock-based employee compensation cost, net income and basic and diluted earnings per share as if the fair value based method of expense recognition and measurement prescribed by SFAS No. 123 had been applied to all options is provided in Note 10, "Stock Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock," herein.

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     The pro forma effect on net income and earnings per share if PHI had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation is as follows:

		For the Year Ended December 31,
		2004		2003		2002
		(Millions, except Per Share Data)
Net Income, as reported	$	258.7	$	113.5	$	210.5
Add:  Total stock-based employee compensation       expense included in net income as reported       (net of related tax effect of       $1.7 million, $1.2 million and $.6 million)		2.6		2.0		1.1
Deduct: Total stock-based employee         compensation expense determined         under fair value based methods for         all awards (net of related tax effect of         $2.5 million, $1.5 million and $.9 million)		(3.8)		(2.6)		(1.7)
Pro forma net income	$	257.5	$	112.9	$	209.9
Basic earnings per share as reported	$	1.47	$	.66	$	1.61
Pro forma earnings per share	$	1.47	$	.66	$	1.60
Diluted earnings per share as reported	$	1.47	$	.66	$	1.61
Pro forma diluted earnings per share	$	1.47	$	.66	$	1.60

Accumulated Other Comprehensive Loss

    A detail of the components of Pepco Holdings' Accumulated Other Comprehensive Loss is as follows. For additional information, refer to the Consolidated Statements of Comprehensive Earnings, herein.

	Commodity Derivatives	Treasury   Lock	Interest Rate Swaps	Marketable Securities	Other (1)	Accumulated Other Comprehensive (Loss) Income
	(Millions of Dollars)
Beginning Balance,   December 31, 2002	$17.2	$(59.7)	$(9.6)	$(0.8)	$   -	$(52.9)
Change during the year	15.0	5.4	6.0	3.8	-	30.2
Beginning Balance,   December 31, 2003	32.2	(54.3)	(3.6)	3.0	-	(22.7)
Current year change	(32.7)	7.2	3.3	(3.0)	(4.1)	(29.3)
Ending Balance,   December 31, 2004	$  (.5)	$(47.1)	$ (.3)	$   -	$(4.1)	$(52.0)
(1)  Represents an adjustment for nonqualified pension plan minimum liability.

    A detail of the income tax expense (benefit) allocated to the components of Pepco Holdings' Other Comprehensive Loss balance is as follows.

	Commodity Derivatives	Treasury   Lock	Interest Rate Swaps	Marketable Securities	Other	Accumulated Other Comprehensive (Loss) Income
	(Millions of Dollars)
December 31, 2002	$ 11.2	$(42.7)	$(4.1)	$ 2.0	$   -	$(33.6)
December 31, 2003	$ 11.1	$  6.3	$ 3.0	$ 2.0	$   -	$ 22.4
December 31, 2004	$(21.6)	$  4.5	$ 1.8	$(1.4)	$(2.8)	$(19.5)

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Income Taxes

     PHI and the majority of its subsidiaries file a consolidated Federal income tax return. Federal income taxes are allocated among PHI and its subsidiaries included in its consolidated group pursuant to a written tax sharing agreement which was approved by the SEC as part of Pepco's acquisition of Conectiv on August 1, 2002. Under this tax sharing agreement, PHI's consolidated federal income tax liability is allocated based upon PHI's and its subsidiaries' separate taxable income or loss, with the exception of the tax benefits applicable to non-acquisition debt expenses of PHI. Such tax benefits are allocated to subsidiaries with taxable income.

     The Consolidated Financial Statements include current and deferred income taxes. Current income taxes represent the amounts of tax expected to be reported on PHI's and its subsidiaries' federal and state income tax returns. Deferred income taxes are discussed below.

     Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement and tax basis of existing assets and liabilities and are measured using presently enacted tax rates. The portion of Pepco's, DPL's, or ACE's deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in "regulatory assets" on the Consolidated Balance Sheets. For additional information, see the discussion under "Regulation of Power Delivery Operations" shown above.

     Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

     Investment tax credits from utility plants purchased in prior years are reported on the Consolidated Balance Sheets as "Investment tax credits." These investment tax credits are being amortized to income over the useful lives of the related utility plant.

SFAS No. 150

     Effective July 1, 2003, Pepco Holdings implemented SFAS No. 150 entitled "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS No. 150). This Statement established standards for how an issuer classifies and measures, in its Consolidated Balance Sheets, certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 resulted in Pepco Holdings' reclassification (initially as of September 30, 2003) of PHI's "Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Which Holds Solely Parent Junior Subordinated Debentures" (TOPrS) and "Mandatorily Redeemable Serial Preferred Stock" on its Consolidated Balance Sheets to a long term liability classification. Additionally, in accordance with the provisions of SFAS No. 150, dividends on the TOPrS and Mandatorily Redeemable Serial Preferred Stock, declared subsequent to the July 1, 2003 imp lementation of SFAS No. 150, are recorded as interest expense in Pepco Holdings' Consolidated Statements of Earnings for the years ended December 31, 2004 and 2003. In accordance with the transition provisions of SFAS No. 150, amounts prior to 2003 were not reclassified.

     In December 2003, the FASB deferred for an indefinite period the application of the guidance in SFAS No. 150 to non-controlling interests that are classified as equity in the financial statements of a subsidiary, but

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would be classified as a liability in the parent's financial statements under SFAS No. 150. The deferral is limited to mandatorily redeemable non-controlling interests associated with finite-lived subsidiaries. Pepco Holdings does not have an interest in any such applicable entities as of December 31, 2004, but will continue to evaluate the applicability of this deferral to entities which may be consolidated as a result of FASB Interpretation No. 46, "Consolidation of Variable Interest Entities."

FIN 45

     Pepco Holdings applied the provisions of FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45), commencing in 2003, to its agreements that contain guarantee and indemnification clauses. These provisions expand those required by FASB Statement No. 5, "Accounting for Contingencies," by requiring a guarantor to recognize a liability on its balance sheet for the fair value of obligations it assumes under certain guarantees issued or modified after December 31, 2002 and to disclose certain types of guarantees, even if the likelihood of requiring the guarantor's performance under the guarantee is remote.

     As of December 31, 2004 and 2003, Pepco Holdings did not have material obligations under guarantees or indemnifications issued or modified after December 31, 2002, that are required to be recognized as a liability on its consolidated balance sheets; however, certain energy marketing obligations of Conectiv Energy were recorded as liabilities.

FIN 46

     On December 31, 2003, FIN 46 was implemented by Pepco Holdings. FIN 46 was revised and superseded by FASB Interpretation No. 46R (revised December 2003), "Consolidation of Variable Interest Entities" (FIN 46R) which clarified some of the provisions of FIN 46 and exempted certain entities from its requirements. FIN 46R was effective December 31, 2003 for variable interest entities that were considered to be special-purpose entities, and effective March 31, 2004 to all other variable interest entities. The implementation of FIN 46R (including the evaluation of interests in power purchase arrangements) did not impact Pepco Holdings' financial condition or results of operations for the years ended December 31, 2004 and 2003.

     As part of its FIN 46R evaluation, Pepco Holdings reviewed its subsidiaries' power purchase agreements (PPAs), including its Non-Utility Generation (NUG) contracts, to determine (i) if the subsidiary's interest in each entity that is a counterparty to a PPA was a variable interest, (ii) whether the entity was a variable interest entity and (iii) if so, whether Pepco Holdings' subsidiary was the primary beneficiary. Due to a variable element in the pricing structure of PPAs with four entities, including Pepco's agreement with Panda-Brandywine, L.P. (Panda), Pepco Holdings' subsidiaries potentially assume the variability in the operations of the plants of these entities and therefore have a variable interest in the entities. Pepco Holdings was unable to obtain sufficient information from these entities to conduct the analysis required under FIN 46R to determine whether these four entities were variable interest entities or if Pepco Holdings' su bsidiaries 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.

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     Net purchase activities with these four entities in the years ended December 31, 2004, 2003, and 2002 were approximately $341 million, $326 million and $316 million, respectively, of which approximately $312 million, $299 million, and $295 million, respectively related to power purchases under the PPAs. Pepco Holdings' exposure to loss under the Panda PPA is discussed in Note (12) Commitments and Contingencies, under "Relationship with Mirant Corporation." Pepco Holdings does not have loss exposure under the remaining three PPAs because cost recovery will be achieved from its customers through regulated rates.

Other Non-Current Assets

     The other assets balance principally consists of real estate under development, equity and other investments, unrealized derivative assets, and deferred compensation trust assets.

Other Current Liabilities

     The other current liability balance principally consists of customer deposits, accrued vacation liability, current unrealized derivative liabilities, and the current portion of deferred income taxes.

Other Deferred Credits

     The other deferred credits balance principally consists of non-current unrealized derivative liabilities and miscellaneous deferred liabilities.

Reclassifications

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

New Accounting Standards

SFAS 123R

     In December 2004, the FASB issued Statement No. 123 (revised 2004), "Share-Based Payment" (FAS 123R) which establishes standards for the accounting for transactions in which an entity exchanges its equity instruments primarily for employee services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity's equity instruments or that may be settled by the issuance of those equity instruments. In most cases, FAS 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award and to recognize that cost over the service period, normally the vesting period. FAS 123R will be effective for Pepco Holdings as of the July 1, 2005. Pepco Holdings is in the process of evaluating the impact of FAS 123R and does not anticipate that its implementati on will have a material effect on its overall financial position or net 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 December 31, 2004 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. Prior to January 1, 2004, Pepco

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Holdings' Power Delivery business consisted of two operating segments, Pepco Power Delivery and Conectiv Power Delivery. However, with the continued integration of the Power Delivery businesses, effective January 1, 2004 management determined that the two businesses represent a single operating segment. Additionally, during the quarter ended March 31, 2004, Pepco Holdings transferred several operating businesses from one operating segment to another in order to better reflect the management of those operations going forward. In accordance with the provisions of SFAS No. 131, results for the years ended December 31, 2003 and 2002 have been reclassified to conform to the current period segment presentation. Intercompany (intersegment) revenues and expenses are not eliminated at the segment level for purposes of presenting segment financial results. Elimination of these intercompany amounts is accomplished for PHI's consolidated results through the "Corporate and Other" column. Segment financial information for the years ended December 31, 2004, 2003 and 2002, is as follows.

		December 31, 2004                               (In Millions)
			Competitive Energy Segments
		Power Delivery	Conectiv Energy	Pepco Energy Services	Other Non- Regulated	Corp.  & Other(a)	PHI Cons.
Operating Revenue		$4,375.9	$2,408.3 (b)	$1,168.6	$87.9	$(818.9)	$ 7,221.8
Operating Expense		3,832.9 (b), (c)	2,281.9	1,150.2	(1.1)(d)	(817.8)	6,446.1
Operating Income		543.0	126.4	18.4	89.0	(1.1)	775.7
Interest Income		5.4	9.9	.7	58.8	(65.4)	9.4
Interest Expense		176.3	47.8 (e)	4.9	94.8	49.8	373.6
Income Taxes (f)		152.5	44.6	4.7	15.1 (i)	(43.7)	173.2
Net Income (loss)		233.4 (c)	54.9 (g)	12.0	25.6 (h)	(67.2)	258.7
Total Assets		8,374.4	1,896.5	544.4	1,319.2	1,214.9	13,349.4
Construction   Expenditures		$  479.5	$   11.6	$   21.2	$      -	$    5.1	$   517.4
(a)	Includes unallocated Pepco Holdings' (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of August 1, 2002. Intercompany eliminations are also included in this line item. Additionally, the line item in this column for "total assets" also includes Pepco Holdings' goodwill balance.
(b)	Power Delivery purchased electric energy, electric capacity and natural gas from Conectiv Energy in the amount of $563.5 million for the year ended December 31, 2004.
(c)	Power Delivery recognized a $14.7 million gain from the condemnation settlement associated with the transfer of certain distribution assets in Vineland, New Jersey. Also, Power Delivery recorded a $6.6 million gain from the sale of non-utility land during the first quarter of 2004.
(d)	Other Non-Regulated recorded an $8.3 million gain from the sale of PCI's final three aircraft.
(e)	Includes $12.8 million of expenses associated with the pre-payment of the Bethlehem debt.
(f)	In February 2004, a local jurisdiction issued final consolidated tax return regulations, which were retroactive to 2001. Under these regulations, Pepco Holdings (parent) 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 the period of 2001 through 2003.
(g)	Conectiv Energy recognized an $11.2 million pre-tax gain ($6.6 million after-tax) from the disposition of a joint venture associated with the Vineland co-generation facility.
(h)	This amount includes the $11.2 million pre-tax impairment charge ($7.3 million after-tax) to reduce the value of the Starpower investment to $28 million at June 30, 2004.
(i)	Includes a $19.7 million charge related to an IRS settlement.

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		December 31, 2003                                                                  (In Millions)
			Competitive Energy Segments
		Power Delivery	Conectiv Energy	Pepco Energy Services	Other Non- Regulated	Corp. & Other(a)	PHI Cons.
Operating Revenue		$4,016.8	$2,859.0 (b)	$1,126.2	$100.1	$  (830.8)	$ 7,271.3
Operating Expense		3,512.0(b)	2,983.5 (c), (d)	1,120.5	(44.1)	(917.0)(c), (d)	6,654.9
Operating Income   (loss)		504.8	(124.5)	5.7	144.2	86.2	616.4
Interest Income		21.7	5.7	.8	49.0	(60.1)	17.1
Interest Expense		167.8	32.3	8.1	96.4	63.7	368.3
Income Taxes		135.5	(53.2)	1.0	(10.1)	(7.3)	65.9
Extraordinary Item   (net of taxes of   $4.1 million)		5.9	-	-	-	-	5.9
Net Income (loss)		209.0	(82.8)(c), (d)	2.0	7.4 (e)	(22.1)(c), (d)	113.5
Total Assets		8,383.5	1,964.5	547.9	1,384.5	1,090.9	13,371.3
Construction   Expenditures		$  383.9	$  199.4	$ 10.8	$      -	$    4.1	$   598.2
Note:	The 2003 operating results above have been revised for the full year to reflect (1) the operations of Pepco Power Delivery and Conectiv Power Delivery as a single Power Delivery segment (2) the transfer of the operations of the Conectiv Energy subsidiary Conectiv Thermal Systems, Inc. (Conectiv Thermal) from Conectiv Energy to Pepco Energy Services, (3) the transfer of the operations of the Deepwater power generation plant (Deepwater) from Power Delivery to Conectiv Energy, and (4) the transfer of the operations of the PCI subsidiary Pepco Enterprises, Inc. (PEI) from PCI (within the "Other Non-Regulated" segment) to Pepco Energy Services.
(a)	Includes unallocated Pepco Holdings' (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization related to purchase accounting adjustments for the Conectiv assets and liabilities as of August 1, 2002. Intercompany transactions are also included in this line item. Additionally, the line item in this column for "total assets" also includes Pepco Holdings' goodwill balance.
(b)	Power Delivery purchased electric energy, electric capacity and natural gas from Conectiv Energy in the amount of $653.3 million for the year ended December 31, 2003.
(c)	Conectiv Energy's results include a charge of $108.0 million ($64.1 million after-tax) related to the CT contract cancellation. This was partially offset by $57.9 million ($34.6 million after-tax) in Corp. & Other, resulting from the reversal of a purchase accounting fair value adjustment made on the date of the merger. Overall, the net impact of these two transactions is $50.1 million ($29.5 million after-tax) on consolidated net income.
(d)	Conectiv Energy's results include a charge of $32.8 million ($19.4 million after-tax) related to an impairment of CT inventory. This was partially offset by $29.6 million ($17.7 million after-tax) in Corp. & Other, resulting from the reversal of a purchase accounting fair value adjustment made on the date of the merger. Overall, the net impact of these two transactions is $3.2 million ($1.7 million after-tax) on consolidated net income.
(e)	Included in "Other Non-Regulated" net income of $7.4 million is a non-cash impairment charge of $102.6 million ($66.7 million after-tax) related to Pepcom's investment in Starpower Communications, LLC. The write-down of the investment in Starpower is based on December 31, 2003 estimated results. Also, included in results is a gain of $68.8 million ($44.7 million after-tax) on the sale of the Edison Place office building and an impairment charge of $11.0 million ($7.2 million after-tax) on PCI's aircraft portfolio.

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		December 31, 2002                                                                 (In Millions)
				Competitive Energy Segments
		Power Delivery	Conectiv Energy		Pepco Energy Services	Other Non- Regulated	Corp. & Other(a)	PHI Cons.
Operating Revenue		$2,519.6	$1,213.3(b)		$865.7	$   89.9	$(364.0)	$ 4,324.5
Operating Expense		2,096.9(b)	1,160.0		852.0	18.2	(348.2)	3,778.9
Operating Income   (loss)		422.7	53.3		13.7	71.7	(15.8)	545.6
Interest Income		20.3	1.4		.9	7.6	(7.9)	22.3
Interest Expense		127.5	15.5		2.1	50.3	18.4	213.8
Income Taxes		123.0	21.7		3.7	(3.6)	(20.7)	124.1
Net Income (loss)		184.4	28.9		7.6	28.1	(38.5)	210.5
Total Assets		8,858.6	1,964.7		465.2	1,736.2	399.4	13,424.1
Construction   Expenditures		$  284.2	$  219.6		$    -	$      -	$    -	$   503.8
Note:	The 2002 operating results above have been revised to reflect (1) the operations of Pepco and Conectiv Power Delivery's post August 1, 2002 merger date results as one Power Delivery segment (2) the transfer of the post August 1, 2002 merger date results of Conectiv Thermal from Conectiv Energy to Pepco Energy Services, (3) the transfer of the post August 1, 2002 merger date results of Deepwater from Power Delivery to Conectiv Energy, and (4) the transfer of the operations of PEI from PCI to Pepco Energy Services.
(a)	Includes primarily severance costs, as well as unallocated Pepco Holdings' (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of August 1, 2002. Intercompany transactions are also included in this line item. Additionally, the line item in this column for "total assets" also includes Pepco Holdings' goodwill balance.
(b)	Power Delivery purchased electric energy, electric capacity and natural gas from Conectiv Energy in the amount of $268.5 million for the period August 1, 2002 through December 31, 2002.

(4)  LEASING ACTIVITIES

     As discussed in Note 2 "Summary of Significant Accounting Policies," in accordance with the provisions of FIN 46, the leveraged lease trusts were deconsolidated from PHI's Consolidated Balance Sheet and the December 31, 2003 balances were presented on the line item "Investment in Finance Leases Held in Trust." The financing lease balances were comprised of the following at December 31:

		2004		2003
		(Millions of Dollars)
Energy leveraged leases	$	1,183.1	$	1,103.5
Aircraft leases		-		1.9
Other		35.6		37.7
Total	$	1,218.7	$	1,143.1

     Pepco Holdings' $1,183.1 million equity investment in energy leveraged leases at December 31, 2004, consists of electric power plants and natural gas transmission and distribution networks located outside of the United States. Of this amount, $415.9 million of equity is attributable to facilities located in The Netherlands, $597.4 million in Austria and $169.8 million in Australia.

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     The components of the net investment in finance leases at December 31, 2004 and 2003 are summarized below (in millions of dollars):

(Millions of Dollars)
At December 31, 2004:	Leveraged  Leases	Direct Finance  Leases	Total Finance  Leases
Rents receivable, net of non-recourse debt	$2,315.4	$26.4	$2,341.8
Residual value	-	12.5	12.5
Less:    Unearned and deferred income	(1,132.3)	(3.3)	(1,135.6)
Investment in finance leases held in trust	1,183.1	35.6	1,218.7
Less:    Deferred taxes	(468.9)	(33.8)	(502.7)
Net Investment in Finance Leases Held in Trust	$  714.2	$ 1.8	$  716.0
At December 31, 2003:	Leveraged  Leases	Direct Finance  Leases	Total Finance  Leases
Rents receivable, net of non-recourse debt	$2,319.1	$41.1	$2,360.2
Residual value	-	12.5	12.5
Less:    Unearned and deferred income	(1,215.6)	(14.0)	(1,229.6)
Investment in finance leases held in trust	1,103.5	39.6	1,143.1
Less:    Deferred taxes	(365.3)	(38.8)	(404.1)
Net Investment in Finance Leases Held in Trust	$  738.2	$  .8	$  739.0

     Income recognized from leveraged leases was comprised of the following:

For the Years Ended December 31,	2004	2003	2002
	(Millions of Dollars)
Pre-tax earnings from leveraged leases	$83.5	$84.2	$64.1
Investment tax credit recognized	-	-	-
Income from leveraged leases, including   investment tax credit	83.5	84.2	64.1
Income tax expense	26.8	21.2	14.2
Net Income from Leveraged Leases Held in Trust	$56.7	$63.0	$49.9

     Rents receivable from leveraged leases are net of non-recourse debt. Minimum lease payments receivable from PCI's finance leases for each of the years 2005 through 2009 and thereafter are zero, $30.7 million, $3.5 million, zero, zero, and $1,184.5 million, respectively.

Lease Commitments

     Pepco leases its consolidated control center, an integrated energy management center used by Pepco's power dispatchers to centrally control the operation of its transmission and distribution systems. The lease is accounted for as a capital lease and was initially recorded at the present value of future lease payments, which totaled $152 million. The lease requires semi-annual payments of $7.6 million over a 25-year period and provides for transfer of ownership of the system to Pepco for $1 at the end of the lease term. Under SFAS No. 71, the amortization of leased assets is modified so that the total interest on the obligation and amortization of the leased asset is equal to the rental expense allowed for rate-making purposes. This lease has been treated as an operating lease for rate-making purposes.

     Rental expense for operating leases was $46.2 million, $32.9 million and $11.6 million for the years ended December 31, 2004, 2003, and 2002.

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     The approximate annual commitments under all operating leases are $38.2 million for 2005, 2006, and 2007, and $39.0 million for 2008 and 2009.

     Capital lease assets recorded within Property, Plant and Equipment at December 31, 2004 and 2003, in millions of dollars, are comprised of the following:

At December 31, 2004	Original Cost	Amortization Accumulated	Net Book Value
Generation	$    .2	$   -	$   .2
Transmission	76.0	13.6	62.4
Distribution	79.7	16.9	62.8
General	2.6	1.2	1.4
Total	$158.5	$31.7	$126.8
At December 31, 2003
Transmission	$ 76.0	$11.6	$ 64.4
Distribution	79.7	14.7	65.0
General	2.6	1.1	1.5
Total	$158.3	$27.4	$130.9

     The approximate annual commitments under all capital leases are $15.9 million for 2005, $15.8 million for 2006, $15.5 million for 2007, $15.4 million for 2008, $15.2 million for 2009, and $152.3 million thereafter. For a discussion of the Federal tax treatment of cross-border leases, refer to Note (12) Commitments and Contingencies.

(5)  PROPERTY, PLANT AND EQUIPMENT

     Property, plant and equipment is comprised of the following.

At December 31, 2004	Original   Cost	Accumulated Depreciation	Net Book Value
	(Millions of Dollars)
Generation	$ 1,847.6	$  520.4	$1,327.2
Distribution	5,712.9	2,193.7	3,519.2
Transmission	1,653.1	648.9	1,004.2
Gas	326.7	93.8	232.9
General	613.7	246.4	367.3
Construction work in progress	405.0	-	405.0
Non-operating and other property	486.2	254.0	232.2
Total	$11,045.2	$3,957.2	$7,088.0
At December 31, 2003
Generation	$2,001.6	$  637.4	$1,364.2
Distribution	5,621.9	2,045.9	3,576.0
Transmission	1,613.4	595.8	1,017.6
Gas	314.5	80.7	233.8
General	640.6	254.1	386.5
Construction work in progress	206.1	-	206.1
Non-operating and other property	349.1	168.4	180.7
Total	$10,747.2	$3,782.3	$6,964.9

     The non-operating and other property amounts include balances for distribution and transmission plant held for future use as well as other property held by non-utility subsidiaries.

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     Pepco Holdings' utility subsidiaries use separate depreciation rates for each electric plant account. The rates vary from jurisdiction to jurisdiction. The system-wide composite depreciation rate for Pepco's transmission and distribution system property was approximately 3.5% in 2004, 2003 and 2002. The system-wide composite depreciation rate in 2004 and 2003 for DPL was approximately 3.1%. The system-wide composite depreciation rates in 2004 and 2003 for ACE were approximately 3.3% and 3.2%, respectively.

     In September 2003, PCI sold its office building known as Edison Place (that serves as headquarters for PHI and Pepco), and recognized a pre-tax gain of $68.8 million ($44.7 million after-tax).

Gain on Sale of Assets

     During 2004 PHI recorded $30.0 million in pre-tax gains on the sale of assets compared to a $68.8 million pre-tax gain in 2003. The 2004 pre-tax gains primarily consist of a $14.7 million pre-tax gain from the condemnation settlement with the City of Vineland relating to the transfer of its distribution assets and customer accounts, an $8.3 million pre-tax gain on the sale of aircraft by PCI, and a $6.6 million pre-tax gain on the sale of land. The $68.8 million pre-tax gain in 2003 represents the gain on the sale of PHI's office building which was owned by PCI.

Jointly Owned Plant

     PHI's Consolidated Balance Sheets include its proportionate share of assets and liabilities related to jointly owned plant. PHI has ownership interests in electric generating plants, transmission facilities, and other facilities in which various parties have ownership interests. PHI's proportionate share of operating and maintenance expenses of the jointly owned plant is included in the corresponding expenses in PHI's Consolidated Statements of Earnings. PHI is responsible for providing its share of financing for the jointly owned facilities. Information with respect to PHI's share of jointly owned plant as of December 31, 2004 is shown below.

Jointly Owned Plant	OwnershipShare	Megawatt CapabilityOwned	Plant inService	AccumulatedDepreciation	Construction Work inProgress
			(Dollars in Millions)
Coal-Fired Electric Generating Plants
Keystone	2.47%	42	$19.7	$ 6.0	$.6
Conemaugh	3.83%	65	37.5	13.1	.3
Transmission   Facilities	Various		35.8	21.0	-
Other Facilities	Various		5.1	1.7	-
Total			$98.1	$41.8	$.9

Combustion Turbine Activity

     During 2003, Conectiv Energy cancelled an order for the purchase of four CTs. The cancellation resulted in a pre-tax loss of $108.0 million at the Conectiv Energy level. The pre-tax loss at the Pepco Holdings level was $50.1 million due to a fair market adjustment recognized by Pepco Holdings at the time of the Conectiv acquisition.

     In addition, during 2003, Conectiv Energy adjusted the value of three CTs that were purchased and delivered in 2002, downward on a pre-tax basis by

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$32.8 million at the Conectiv Energy level, to reflect the current fair value of the CTs. The loss at the Pepco Holdings level was $3.2 million pre-tax due to a fair market adjustment recognized by Pepco Holdings at the time of the acquisition of Conectiv by Pepco. In December 2003, Conectiv Energy reclassified the CTs from construction work in process to other non-current assets to reflect the uncertain timing of the installation or future use.

(6)  PENSIONS AND OTHER POST-RETIREMENT BENEFITS

Pension Benefits

     Pepco Holdings sponsors a retirement plan that covers substantially all employees of Pepco, Conectiv and certain employees of other Pepco Holdings' subsidiaries (Retirement Plan). Following the consummation of the acquisition of Conectiv by Pepco on August 1, 2002, the Pepco General Retirement Plan and the Conectiv Retirement Plan were merged into the Retirement Plan on December 31, 2002. The provisions and benefits of the merged Retirement Plan for Pepco employees are identical to those of the original Pepco plan and for Conectiv employees the provisions and benefits are identical to those of the original Conectiv plan. Pepco Holdings also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans. Pepco Holdings uses a December 31 measurement date for its plans.

     The acquisition of Conectiv by Pepco in August 2002 resulted in purchase accounting requirements that are reflected in the net periodic pension cost. Under this accounting treatment, Conectiv's accrued pension liability was adjusted on August 1, 2002 through consolidation to recognize all previously unrecognized gains and losses arising from past experience different from that assumed, all unrecognized prior service costs, and the remainder of any unrecognized obligation or asset existing at the date of the initial application of SFAS No.87, "Employers' Accounting for Pensions." The Conectiv Retirement Plan transferred a projected benefit obligation of $804 million and plan assets of $744 million on August 1, 2002.

     Plan assets are stated at their market value as of the measurement date, December 31. All dollar amounts in the following tables are in millions of dollars.

     The following tables provide a roll forward of the changes in the projected benefit obligation and plan assets for the most recent two years.

	Pension Benefits
Change in Benefit Obligation	2004	2003
Benefit obligation at beginning of year	$1,579.2	$1,398.9
Service cost	35.9	33.0
Interest cost	94.7	93.7
Actuarial loss	51.4	144.4
Benefits paid	(113.2)	(90.8)
Benefit obligation at end of year	$1,648.0	$1,579.2
Change in Plan Assets
Fair value of plan assets at beginning of year	$1,462.8	$1,240.6
Actual return on plan assets	161.1	261.5
Company contributions	12.8	51.5
Benefits paid	(113.2)	(90.8)
Fair value of plan assets at end of year	$1,523.5	$1,462.8

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     The following table provides a reconciliation of the projected benefit obligation, plan assets and funded status of the plans.

	Pension Benefits
	2004	2003
Fair value of plan assets at end of year	$1,523.5	$1,462.8
Benefit obligation at end of year	1,648.0	1,579.2
Funded status (plan assets less than plan obligations)	$(124.5)	$(116.4)
Amounts not recognized:
Unrecognized net actuarial loss	261.2	253.3
Unrecognized prior service cost	3.0	4.0
Net amount recognized	$ 139.7	$ 140.9

     The following table provides a reconciliation of the amounts recognized in PHI's Consolidated Balance Sheets as of December 31:

	Pension Benefits
	2004	2003
Prepaid benefit cost	$165.7	$166.6
Accrued benefit cost	(26.0)	(25.7)
Additional minimum liability for nonqualified plan	(7.0)	-
Intangible assets for nonqualified plan	.1	-
Accumulated other comprehensive income for   nonqualified plan	6.9	-
Net amount recognized	$139.7	$140.9

     The accumulated benefit obligation for the Retirement Plan (the qualified defined benefit pension plan) was $1,462.9 million and $1,409.0 million at December 31, 2004, and 2003, respectively. The table below provides the projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the PHI nonqualified pension plan with an accumulated benefit obligation in excess of plan assets at December 31, 2004.

	Pension Benefits
	2004	2003
Projected benefit obligation for nonqualified plan	$35.3	$34.3
Accumulated benefit obligation for nonqualified plan	$32.9	$24.0
Fair value of plan assets for nonqualified plan	-	-

     In 2004, PHI was required to recognize an additional minimum liability and an intangible asset related to its nonqualified pension plan as prescribed by SFAS No. 87. The liability was recorded as a reduction to shareholders' equity (other comprehensive income), and the equity will be restored to the balance sheet in future periods when the accrued benefit liability exceeds the accumulated benefit obligation at future measurement dates. The amount of reduction to shareholders' equity (net of income taxes) in 2004 was $4.1 million. The recording of this reduction did not affect net income or cash flows in 2004 or compliance with debt covenants.

	Pension Benefits
Other additional information:	2004	2003
Decrease in other comprehensive income	$4.1	-

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     The table below provides the components of net periodic benefit costs recognized for the years ended December 31. A portion of the net periodic benefit cost is capitalized within PHI's Consolidated Balance Sheets.

Components of Net Periodic Benefit Cost
	Pension Benefits
	2004	2003	2002
Service cost	$  35.9	$  33.0	$  16.0
Interest cost	94.7	93.7	54.1
Expected return on plan assets	(124.2)	(106.2)	(69.0)
Amortization of prior service cost	1.1	1.0	1.0
Amortization of net (gain) loss	6.5	13.9	6.9
Net periodic benefit cost	$  14.0	$  35.4	$  9.0

     The 2004 net periodic benefit cost of $14.0 million includes $7.5 million for Pepco, $(8.7) million for DPL and $7.1 million for ACE. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries.

     The 2003 net periodic benefit cost of $35.4 million includes $15.7 million for Pepco, $(1.8) million for DPL and $10.8 million for ACE. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries.

     The 2002 net periodic benefit cost amount of $9.0 million includes $6.1 million for Pepco, and $(3.3) million for DPL and $4.9 million for ACE for the period August 1, 2002 to December 31, 2002. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries.

     The following weighted average assumptions were used to determine the benefit obligations at December 31:

Assumptions
Weighted-average assumptions used to determine benefit obligations at December 31
	Pension Benefits
	2004	2003
Discount rate	5.875%	6.25%
Rate of compensation increase	4.50%	4.50%

     The following weighted average assumptions were used to determine the net periodic benefit cost for years ended December 31:

Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31
	Pension Benefits
	2004	2003
Discount rate	6.25%	6.75%
Expected long-term return on plan assets	8.75%	8.75%
Rate of compensation increase	4.50%	4.50%

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     In selecting an expected rate of return on plan assets, PHI considers actual historical returns, economic forecasts and the judgment of its investment consultants on expected long-term performance for the types of investments held by the plan. The plan assets consist of equity and fixed income investments, and when viewed over a long time horizon, are expected to yield a return on assets of 8.75%.

Plan Assets

     Pepco Holdings' pension plan weighted-average asset allocations at December 31, 2004, and 2003, by asset category are as follows:

Asset Category	Plan Assets at December 31 2004      2003		Target Plan Asset Allocation	Minimum/ Maximum
Equity securities	66%	64%	60%	55% - 65%
Debt securities	33%	35%	35%	30% - 50%
Other	1%	1%	5%	0% - 10%
Total	100%	100%	100%

     In developing an asset allocation policy for its Retirement Plan, PHI examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, PHI examined the risk/return tradeoffs of alternative asset classes and asset mixes given long-term historical relationships, as well as prospective capital market returns. PHI also conducted an asset/liability study to match projected asset growth with projected liability growth and provide sufficient liquidity for projected benefit payments. By incorporating the results of these analyses with an assessment of its risk posture, and taking into account industry practices, PHI developed its asset mix guidelines. Under these guidelines, PHI diversifies assets in order to protect against large investment losses and to reduce the probability of excessive performance volatility while maximizing return at an acceptable risk level. Diversification of assets is impleme nted by allocating monies to various asset classes and investment styles within asset classes, and by retaining investment management firm(s) with complementary investment philosophies, styles and approaches. Based on the assessment of demographics, actuarial/funding, and business and financial characteristics, PHI believes that its risk posture is slightly below average relative to other pension plans. Consequently, Pepco Holdings believes that a slightly below average equity exposure (i.e., a target equity asset allocation of 60%) is appropriate for the Retirement Plan.

     On a periodic basis, Pepco Holdings reviews its asset mix and rebalances assets back to the target allocation over a reasonable period of time.

     No Pepco Holdings common stock is included in pension program assets.

Cash Flows

Contributions

     Pepco Holdings, Inc. funding policy with regard to the Retirement Plan is to maintain a funding level in excess of 100% with respect to its accumulated benefit obligation (ABO). PHI's Retirement Plan defined benefit plan currently meets the minimum funding requirements of ERISA without any additional funding. In 2004 and 2003, PHI made discretionary tax-deductible cash contributions to the plan of $10.0 million and $50.0 million, respectively, in line with its funding policy. Assuming no changes to the

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current pension plan assumptions, PHI projects no funding will be required under ERISA in 2005; however, PHI may elect to make a discretionary tax-deductible contribution, if required to maintain its plan assets in excess of its ABO.

Expected Benefit Payments

     The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid from the Retirement Plan:

Years	Pension       Benefits
2005	$ 89.4
2006	91.6
2007	102.0
2008	108.2
2009	113.4
2010-2014	619.7

Other Post-Retirement Benefits

     In addition to sponsoring non-contributory retirement plans, Pepco Holdings provides certain post-retirement health care and life insurance benefits for eligible retired employees. Certain groups of employees hired January 1, 2005 or later will not have company subsidized retiree medical coverage; however, they will be able to purchase coverage at full cost through the company. Pepco Holdings uses a December 31 measurement date for its plans.

     The acquisition of Conectiv by Pepco in August 2002 resulted in purchase accounting requirements that are reflected in the net periodic benefit cost. Under this accounting treatment, Conectiv's accrued post-retirement health care and life insurance liability was adjusted on August 1, 2002 through consolidation to recognize all previously unrecognized actuarial gains and losses, all unrecognized prior service costs, and the remainder of any unrecognized obligation or asset existing at the date of the initial application of SFAS No. 106. The Conectiv Plan transferred a projected benefit obligation of $320 million and plan assets of $100 million on August 1, 2002.

     During 2004, PHI announced amendments to its post-retirement health care plans for certain groups of eligible employees. The amendments included changes to coverage and retiree cost-sharing, and are reflected as a reduction in PHI's 2004 net periodic benefit cost and a reduction of $42 million in projected benefit obligation at December 31, 2004.

     Plan assets are stated at their market value as of the measurement date, December 31. All dollar amounts in the following tables are in millions of dollars.

     The following tables provide a roll forward of the changes in the benefit obligation and plan assets for the most recent two years: 

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	Other Post- Retirement Benefits
	2004	2003
Change in Benefit Obligation
Benefit obligation at beginning of year	$ 511.9	$ 472.4
Service cost	8.6	9.4
Interest cost	35.4	32.9
Amendments	(42.4)	-
Actuarial loss	117.0	31.0
Benefits paid	(37.0)	(33.8)
Benefit obligation at end of year	$ 593.5	$ 511.9
Change in Plan Assets
Fair value of plan assets at beginning of year	$ 145.2	$ 123.0
Actual return on plan assets	15.7	25.8
Company contributions	41.0	30.2
Benefits paid	(37.0)	(33.8)
Fair value of plan assets at end of year	$ 164.9	$ 145.2

     The following table provides a reconciliation of benefit obligations, plan assets and funded status of the plans:

	Other Post- Retirement Benefits
	2004	2003
Fair value of plan assets at end of year	$164.9	$145.2
Benefit obligation at end of year	593.5	511.9
Funded status (plan assets less than plan obligations)	(428.6)	(366.7)
Amounts not recognized:
Unrecognized net actuarial loss	188.5	89.0
Unrecognized initial net obligation	(29.5)	10.8
Net amount recognized	$(269.6)	$(266.9)

     The following table provides a reconciliation of the amounts recognized in PHI's Consolidated Balance Sheets as of December 31:

	Other Post- Retirement Benefits
	2004	2003
Prepaid benefit cost	$     -	$     -
Accrued benefit cost	(269.6)	(266.9)
Net amount recognized	$(269.6)	$(266.9)

     The table below provides the components of net periodic benefit costs recognized for the years ended December 31. A portion of the net periodic benefit cost is capitalized within PHI's Consolidated Balance Sheets.

Components of Net Periodic Benefit Cost
	Other Post- Retirement Benefits
	2004	2003	2002
Service cost	$ 8.6	$ 9.5	$ 7.2
Interest cost	35.4	32.9	20.0
Expected return on plan assets	(9.9)	(8.3)	(5.2)
Recognized actuarial loss	9.5	8.0	6.1
Net periodic benefit cost	$43.6	$42.1	$28.1

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     The 2004 net periodic benefit cost amount of $43.6 million, includes $16.7 million for Pepco, $9.5 million for DPL and $10.5 million for ACE. The remaining net periodic benefit cost is related to other PHI subsidiaries. The 2003 net periodic benefit cost amount of $42.1 million, includes $18.0 million for Pepco, $9.0 million for DPL and $10.0 million for ACE. The remaining net periodic benefit cost is related to other PHI subsidiaries. The 2002 net periodic benefit cost amount of $28.1 million includes $18.4 million for Pepco, and $2.1 million of DPL and $4.3 million of ACE for the period August 1, 2002 to December 31, 2002. The remaining 2002 net periodic benefit cost is related to other PHI subsidiaries.

     The following weighted average assumptions were used to determine the benefit obligations at December 31:

Assumptions
Weighted-average assumptions used to determine benefit obligations at December 31
	Other Post- Retirement Benefits
	2004	2003
Discount rate	5.875%	6.25%
Rate of compensation increase	4.50%	4.50%

     The following weighted average assumptions were used to determine the net periodic benefit cost for years ended December 31:

Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31
	Other Post- Retirement Benefits
	2004	2003
Discount rate	6.25%	6.75%
Expected long-term return on plan assets	8.75%	8.75%
Rate of compensation increase	4.50%	4.50%

     In selecting an expected rate of return on plan assets, PHI considers actual historical returns, economic forecasts and the judgment of its investment consultants on expected long-term performance for the types of investments held by the plan. The plan assets consist of equity and fixed income investments, and when viewed over a long time horizon, are expected to yield a return on assets of 8.75%.

     The table below provides the assumed health care trend rates as of December 31:

Assumed health care cost trend rates at December 31
	2004	2003
Health care cost trend rate assumed for next year	9%	8%
Rate to which the cost trend rate is assumed to   decline (the ultimate trend rate)	5%	5%
Year that the rate reaches the ultimate trend rate	2009	2007

     Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

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	1-Percentage- Point Increase	1-Percentage- Point Decrease
Effect on total of service and interest cost	$ 1.8	$ (1.7)
Effect on post-retirement benefit obligation	25.0	(23.0)

Plan Assets

     Pepco Holdings' post-retirement plan weighted-average asset allocations at December 31, 2004, and 2003, by asset category are as follows:

	Plan Assets    at December 31,    2004         2003
Asset Category
Equity securities	65%	63%
Debt securities	35%	37%
Total	100%	100%

     No Pepco Holdings common stock is included in post-retirement program assets.

Cash Flows

Contributions

     Pepco funded the 2004 and 2003 portions of its estimated liability for Pepco post-retirement medical and life insurance costs through the use of an Internal Revenue Code (IRC) 401 (h) account, within Pepco Holdings' Retirement Plan, and an IRC 501 (C) (9) Voluntary Employee Beneficiary Association (VEBA). DPL and ACE funded a portion of their estimated post-retirement liability through their VEBAs. In 2004 and 2003, Pepco contributed $4.7 million and $4.1 million, respectively, DPL contributed $9.5 million and $9.0 million, respectively. ACE contributed $9.3 million and $5.3 million, respectively, to the plans. Contributions of $5.0 million and $8.5 million, respectively, were made by other PHI subsidiaries. Assuming no changes to the current pension plan assumptions, PHI expects similar amounts to be contributed in 2005.

Expected Benefit Payments

     The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Years	Pension       Benefits
2005	$ 36.0
2006	36.3
2007	38.6
2008	40.6
2009	42.4
2010-2014	225.3

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     FASB Staff Position (FSP 106-2), Accounting and Disclosure
       Requirements Related to the Medicare Prescription Drug, Improvement
       and Modernization Act of 2003

     The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) became effective on December 8, 2003. The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

     Pepco Holdings sponsors post-retirement health care plans that provide prescription drug benefits. Pepco Holdings did not elect the deferral of appropriate accounting permitted by the FASB Staff position (FSP) 106-1. The Accumulated Post-retirement Benefit Obligation (APBO) as of December 31, 2004 and December 31, 2003 has been reduced by $28 million to reflect the effects of the Act. This reduction includes both the decrease in the cost of future benefits being earned and an amortization of the APBO reduction over the future average working lifetime of the participants, or 12 years.The anticipated claims costs expected to be incurred have been adjusted to reflect the cost sharing between Medicare and Pepco Holdings. Participation rates have not been changed. In reflecting the effects of the Act, Pepco Holdings has determined which plans are eligible for Medicare cost sharing by analyzing the terms of each of its plans. It has rec ognized Medicare cost sharing for a plan only if Pepco Holdings' projected prescription drug coverage is expected to be at least as generous as the expected contribution by Medicare to a prescription drug plan not provided by Pepco Holdings.

     The effect of the subsidy on the 2004 other post-retirement net periodic benefit cost of $43.6 million is approximately a $3.6 million reduction due to the subsidy. Approximately $2.0 million is related to the amortization of the actuarial gain, and approximately $1.6 million is a subsidy-related reduction in interest cost on the APBO.

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(7)  DEBT

     LONG-TERM DEBT

     The components of long-term debt are shown below.

				At December 31,��
Interest Rate		Maturity		2004		2003
				(Millions of Dollars)
First Mortgage Bonds
Pepco:
6.50%		2005		100.0		100.0
6.25%		2007		175.0		175.0
6.50%		2008		78.0		78.0
5.875%		2008		50.0		50.0
5.75% (a)		2010		16.0		16.0
4.95% (a)		2013		200.0		200.0
4.65% (a)		2014		175.0		-
6.00% (a)		2022		30.0		30.0
6.375% (a)		2023		37.0		37.0
6.875%		2023		-		100.0
5.375% (a)		2024		42.5		42.5
5.375% (a)		2024		38.3		38.3
6.875%		2024		-		75.0
7.375%		2025		75.0		75.0
5.75% (a)		2034		100.0		-
DPL:
7.71%		2025		100.0		100.0
ACE:
6.18% - 7.98%		2004 - 2008		156.0		165.0
7.25% - 7.63%		2010 - 2014		8.0		8.0
6.63%		2013		68.6		68.6
7.68%		2015 - 2016		17.0		17.0
6.80% (a)		2021		38.9		38.9
7.00%		2023		-		62.5
5.60% (a)		2025		4.0		4.0
6.15% - 7.20%		2028 - 2029		-		129.7
Variable (a)		2029		54.7		-
5.80% (a)		2034		120.0		-
Amortizing First Mortgage Bonds
DPL:
6.95%		2004 - 2008		13.2		15.7
ACE:
6.375% (a)		2004 - 2006		-		2.0
Total First Mortgage Bonds			$	1,697.2	$	1,628.2
(a)	First Mortgage Bonds issued as security for tax-exempt bonds and senior notes.
NOTE:    Schedule is continued on next page. 196 _____________________________________________________________________________

			At December 31,
Interest Rate	Maturity		2004		2003
			(Millions of Dollars)
Unsecured Tax-Exempt Bonds
DPL:
5.20%	2019	$	31.0	$	31.0
3.15%	2023		18.2		18.2
5.50%	2025		15.0		15.0
4.90%	2026		34.5		34.5
5.65%	2028		16.2		16.2
Variable	2030 - 2038		93.4		93.4
Total Unsecured Tax-Exempt Bonds			208.3		208.3
Medium-Term Notes (unsecured)
Pepco:
7.64%	2007		35.0		35.0
6.25%	2009		50.0		50.0
7.00%	2024		-		35.0
DPL:
8.30%	2004		-		4.5
6.75%	2006		20.0		20.0
7.06% - 8.13%	2007		61.5		61.5
7.56% - 7.58%	2017		14.0		14.0
6.81%	2018		4.0		4.0
7.61%	2019		12.0		12.0
7.72%	2027		10.0		10.0
ACE:
7.50% - 7.52%	2007		15.0		15.0
CIV:
5.30%	2005		250.0		250.0
6.73%	2006		50.0		100.0
Total Medium-Term Notes (unsecured)		$	521.5	$	611.0

NOTE:    Schedule is continued on next page.

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					At December 31,
Interest Rate		Maturity			2004			2003
					(Millions of Dollars)
Recourse Debt
PCI:
4.00% - 4.99%	2008		$	92.0		$	92.0
6.00% - 6.99%	2004 - 2014			71.1			99.4
7.00% - 8.99%	2004 - 2007			34.3			86.8
Total Recourse Debt				197.4			278.2
Notes (secured)
Pepco Energy Services:
7.85%	2017			9.2			8.5
Notes (unsecured)
PHI:
Variable	2004			-			200.0
3.75% - 5.50%	2006 - 2007			800.0			800.0
4.00% - 6.45%	2010 - 2012			950.0			950.0
7.45%	2032			250.0			250.0
PEPCO
Variable	2006			100.0			-
DPL:
5.0%	2014			100.0			-
Total Notes (unsecured)				2,200.0			2,200.0
Nonrecourse debt
PCI:
6.60%	2018			17.1			18.1
Acquisition fair value adjustment				.2			.7
Total Long-Term Debt				4,850.9			4,953.0
Net unamortized discount				(6.1)			(10.1)
Current portion of long-term debt (a)				(482.7)			(354.0)
Total Net Long-Term Debt			$	4,362.1		$	4,588.9
Transition Bonds issued by     ACE Funding:
2.89%	2010		$	75.2		$	94.5
2.89%	2011			39.4			46.0
4.21%	2013			66.0			66.0
4.46%	2016			52.0			52.0
4.91%	2017			118.0			118.0
5.05%	2018			54.0			54.0
5.50%	2023			147.0			147.0
Total				551.6			577.5
Net unamortized discount				(.1)			(.3)
Current portion of long-term debt       (included in short-term debt)				(28.2)			(25.9)
Total Transition Bonds issued by     ACE Funding			$	523.3		$	551.3
(a) Included in short-term debt.

     The outstanding First Mortgage Bonds issued by each of Pepco, DPL and ACE are secured by a lien on substantially all of the issuing company's property, plant and equipment.

     The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond charges collected from ACE's customers are not available to creditors of ACE. The Transition Bonds are obligations of ACE Funding and are non-recourse to ACE.

     The aggregate amounts of maturities for long-term debt and transition bonds outstanding at December 31, 2004, are $510.9 million in 2005, $536.9

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million in 2006, $854.9 million in 2007, $305.3 million in 2008, $82.2 million in 2009, and $3,111.9 million thereafter.

     Project Funding Secured by Customer Accounts Receivable represents funding for energy savings contracts performed by Pepco Energy Services and includes the current portion of project funding that was provided in exchange for the sale of the customers' account receivable.

     The aggregate amounts of maturities for the Project Funding Secured by Customer Accounts Receivable debt outstanding at December 31, 2004, are $5.4 million in 2005, $5.8 million in 2006, $6.3 million in 2007, $6.6 million in 2008, $6.2 million in 2009, and $40.4 million, thereafter.

SHORT-TERM DEBT

     Pepco Holdings and its regulated utility subsidiaries have traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. A detail of the components of Pepco Holdings' short-term debt at December 31, 2004 and 2003 is as follows.

	2004	2003
	(Millions of Dollars)
Commercial paper	$111.3	$    -
Construction loan	-	310.0
Project funding	5.4	5.0
Floating rate note	50.0	50.0
Variable rate demand bonds	158.4	158.4
Current portion of long-term debt	510.9	379.9
Total	$836.0	$903.3

Commercial Paper

     Pepco Holdings maintains an ongoing commercial paper program of up to $700 million. Pepco, DPL, and ACE have ongoing commercial paper programs of up to $300 million, up to $275 million, and up to $250 million, respectively. The commercial paper programs of PHI, Pepco, DPL and ACE are backed by $1.2 billion in credit facilities. Pepco Holdings' credit limit under these facilities is $700 million, and the credit limit of each of Pepco, DPL and ACE under these facilities is the lower of $300 million and the maximum amount of short-term debt authorized by the applicable regulatory authority, except that the aggregate amount of credit utilized by Pepco, DPL and ACE at any given time under these facilities may not exceed $500 million. The commercial paper notes can be issued with maturities up to 270 days from the date of issue.

     Pepco Holdings and ACE had $78.6 million and $32.7 million of commercial paper outstanding at December 31, 2004, respectively. Pepco and DPL had no commercial paper outstanding at December 31, 2004. Interest rates for commercial paper issued during 2004 ranged from 1.05% to 2.63%. Interest rates for commercial paper issued during 2003 ranged from 1.00% to 1.60%. Maturities were less than 270 days for all commercial paper issued.

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Construction Loan

     In June 2004, Conectiv Bethlehem converted its $335 million construction loan to a two-year term loan due 2006. Conectiv Bethlehem entered into an interest rate swap agreement which effectively converted the variable interest rate on 75% of the expected loan balance to a fixed rate of 4.15%. In September 2004, Conectiv Bethlehem prepaid the entire $335 million loan and settled the swap agreement for $6.8 million in interest expense. Interest rates for borrowings under the construction and term loan ranged from 2.72% to 4.88% in 2004 and from 2.74% to 3.07% in 2003.

Floating Rate Note

     In December 2004, Pepco Holdings issued a $50 million floating rate note. At December 31, 2004, the interest rate on this note was 2.81%. A $50 million floating rate note previously issued by Pepco matured in March 2004, on which the interest rate ranged from 1.60% to 1.61% during 2004 and 1.62% to 1.69% during 2003.

Variable Rate Demand Bonds

     Variable Rate Demand Bonds ("VRDB") are included in short-term debt because the VRDB are due on demand by the bondholder. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. PHI expects the bonds submitted for purchase will continue to be remarketed successfully due to the credit worthiness of the respective issuers and because the remarketing resets interest rates on the bonds at market rates. The respective issuers also may utilize one of the fixed rate/fixed term conversion options of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. The VRDB outstanding in 2004 and 2003 mature in 2005 to 2009 ($12.5 million), 2014 to 2017 ($48.6 million), 2024 ($33.3 million) and 2028 to 2031 ($64.0 million). Interest rates ranged from .82% to 2.47% in 2004 and .60% to 1.90% in 2003.

Credit Facility Agreements

     In July 2004, Pepco Holdings, Pepco, DPL and ACE entered into a five-year credit agreement with an aggregate borrowing limit of $650 million. This agreement replaced a $550 million 364-day credit agreement that was entered into on July 29, 2003. The respective companies also are parties to a three-year credit agreement that was entered into in July 2003 and terminates in July 2006 with an aggregate borrowing limit of $550 million. Pepco Holdings' credit limit under these facilities is $700 million, and the credit limit of each of Pepco, DPL and ACE under these facilities is the lower of $300 million and the maximum amount of short-term debt authorized by the appropriate state commission, except that the aggregate amount of credit utilized by Pepco, DPL and ACE at any given time under these facilities may not exceed $500 million. Funds borrowed under these facilities are available for general corporate purposes. Either credit facility also can be used as credit support for the commercial paper programs of the respective companies. The three-year and five-year credit agreements contain customary financial and other covenants that, if not satisfied, could result in the acceleration of repayment obligations under the agreements or restrict the ability of the companies to borrow under the agreements. Among these covenants is 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 agreements. As of December 31, 2004, the applicable ratios for Pepco Holdings, Pepco, DPL and ACE were 59.0%, 58.5%,

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52.1% and 50.2%, respectively. The credit agreements also contain a number of customary events of default that could result in the acceleration of repayment obligations under the agreements, including (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 agreements) of Pepco Holdings or the failure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE.

(8)  INCOME TAXES

     PHI and the majority of its subsidiaries file a consolidated federal income tax return. Federal income taxes are allocated among PHI and its subsidiaries included in its consolidated group pursuant to a written tax sharing agreement which was approved by the SEC as part of Pepco's acquisition of Conectiv on August 1, 2002. Under this tax sharing agreement, PHI's consolidated federal income tax liability is allocated based upon PHI's and its subsidiaries' separate taxable income or loss, with the exception of the tax benefits applicable to non-acquisition debt expenses of PHI. Such tax benefits are allocated to subsidiaries with taxable income.

     The provision for income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred tax liabilities (assets) are shown below.

Provision for Income Taxes

	For the Year Ended December 31,
	2004	2003	2002
	(Millions of Dollars)
Current Tax Expense
Federal	$(27.3)	$(126.5)	$(305.0)
State and local	(9.0)	36.0	(17.2)
Total Current Tax (Benefit) Expense	(36.3)	(90.5)	(322.2)
Deferred Tax Expense
Federal	185.1	172.6	400.5
State and local	32.4	(10.9)	49.2
Investment tax credits	(8.0)	(5.3)	(3.4)
Total Deferred Tax Expense	209.5	156.4	446.3
Total Income Tax Expense	$173.2	$  65.9	$ 124.1

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Reconciliation of Consolidated Income Tax Expense

		For the Year Ended December 31,
		2004					2003					2002
		Amount		Rate			Amount		Rate			Amount		Rate
	(Millions of Dollars)
Income Before Income Taxes	$	431.9				$	173.5				$	334.6
Preferred dividends		2.8					4.7					5.7
Income Before Income Taxes	$	434.7				$	178.2				$	340.3
Income tax at federal statutory rate	$	152.1		.35		$	62.4		.35		$	119.1		.35
Increases (decreases) resulting from
Depreciation		9.4		.02			8.2		.05			6.6		.02
Removal costs		(1.7	)	-			(4.6	)	(.03	)		(2.4	)	(.01	)
State income taxes, net of       federal effect		29.4		.07			16.3		.09			20.7		.06
Tax credits		(5.9	)	(.01	)		(5.1	)	(.03	)		(4.0	)	(.01	)
Cumulative effect of local       tax consolidation		(13.2	)	(.03	)		-					-
IRS settlement		19.7		.05			-					-
Company dividends reinvested       in 401(k) plan		(2.1	)	(.01	)		(1.4	)	.01			-
Leveraged leases		(8.2	)	(.02	)		(8.2	)	(.05	)		(8.3	)	(.03	)
Other		(6.3	)	(.02	)		(1.7	)	(.02	)		(7.6	)	(.02	)
Total Income Tax Expense	$	173.2		.40		$	65.9		.37		$	124.1		.36

Components of Consolidated Deferred Tax Liabilities (Assets)

	At December 31,
			2004			2003
	(Millions of Dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other book to tax basis differences		$	1,709.8		$	1,606.9
Deferred taxes on amounts to be collected through     future rates			57.1			58.7
Deferred investment tax credit			(30.9	)		(37.2	)
Contributions in aid of construction			(56.9	)		(67.6	)
Goodwill, accumulated other comprehensive income,     and valuation adjustments			(161.4	)		(169.9	)
Deferred electric service and electric restructuring     liabilities			(5.2	)		(7.9	)
Finance and operating leases			434.8			332.8
NUG contract			82.1			86.7
Capital loss carry forward			(14.3	)		-
Federal net operating loss			(65.7	)		(70.1	)
Federal Alternative Minimum Tax credit			(5.6	)		-
State net operating loss			(63.7	)		(22.6	)
Valuation allowance (State NOLs)			33.9			-
Other post-retirement benefits			(36.2	)		(18.9	)
Unrealized losses on fair value declines			(6.2	)		20.8
Property taxes, contributions to pension plan, and other			40.0			33.0
Total Deferred Tax Liabilities, Net			1,911.6			1,744.7
Deferred tax liabilities included in   Other Current Liabilities			70.2			(56.0	)
Total Deferred Tax Liabilities, Net Non-Current		$	1,981.8		$	1,688.7

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     At December 31, 2004, PHI had unused federal net operating loss carry forwards of $196.9 million which will expire in 2018. Since PHI expects to fully utilize this Federal net operating loss, no valuation allowance is necessary. As of December 31, 2004, PHI also has $1,135.2 million unused state net operating loss carry forwards, which will expire in various amounts through 2024. PHI has recorded a $33.9 million (tax effected) valuation allowance due to the uncertainty of full utilization of all these State net operating loss carry forwards. As of December 31, 2004, PHI also had unused capital loss carry forwards of approximately $39.3 million, which will expire in 2009 unless utilized. Since PHI expects to fully utilize these capital losses, no valuation allowance is necessary.

     The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to PHI's operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net and is recorded as a regulatory asset on the balance sheet.

     The Tax Reform Act of 1986 repealed the Investment Tax Credit (ITC) for property placed in service after December 31, 1985, except for certain transition property. ITC previously earned on Pepco's, DPL's and ACE's property continues to be normalized over the remaining service lives of the related assets.

     PHI files a consolidated federal income tax return. PHI's federal income tax liabilities for Pepco legacy companies for all years through 2000, and for Conectiv legacy companies for all years through 1997 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carry backs from subsequent years. Except for cross-border leases, which are more fully discussed below, PHI believes that the final settlement of its federal income tax liabilities for subsequent years will not have a material adverse effect on its financial condition or results of operations.

PHI Earnings Charge Relating to Additional Tax Liability

     The Internal Revenue Service (IRS), as part of its normal audit of PHI's income tax returns, questioned whether PHI is entitled to certain ongoing tax deductions being taken by PHI as a result of the adoption by PHI of a carry-over tax basis for a non-lease financial asset acquired in 1998 by a subsidiary of PHI. On December 14, 2004, PHI and the IRS agreed to a Notice of Proposed Adjustment settling this and certain other tax matters. This settlement will result in a cash outlay for additional taxes and interest of approximately $21.4 million when the current examination is completed in 2005, and an anticipated refund of taxes and interest of approximately $6.4 million when the examination of PHI's 2003 return is completed. In addition, in the fourth quarter of 2004 PHI took a tax charge to earnings of approximately $19.7 million for financial reporting purposes. The charge consists of approximately $16.3 million to reflect the reversal of tax benefits recognized by PHI prior to September 30, 2004, and approximately $3.4 million of interest on the additional taxes.

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Taxes Other Than Income Taxes

     Taxes, other than income taxes, for each period are shown below.

	2004	2003	2002
Gross Receipts/Delivery	$137.8	$138.4	$111.3
Property	51.8	59.3	51.1
County Fuel and Energy	70.6	36.7	17.9
Environmental, Use and Other	42.6	39.5	45.3
Total	$302.8	$273.9	$225.6

(9)  PREFERRED STOCK OF SUBSIDIARIES

     Preferred stock amounts outstanding as of December 31, 2004 and 2003 are as follows:

Issuer and Series		Redemption   Price	Shares Outstanding  2004       2003		December 31,    2004       2003
						(Millions of Dollars)
Serial Preferred
Pepco	$2.44 Series of 1957	$51.00	239,641	239,641		$	12.0	$	12.0
Pepco	$2.46 Series of 1958	$51.00	173,892	173,892			8.7		8.7
Pepco	$2.28 Series of 1965 (1)	$51.00	125,857	291,759			6.3		14.6
						$	27.0	$	35.3
Mandatorily Redeemable Serial Preferred
Pepco	$3.40 Series of 1992 (2)	$50.00	-	900,000		$	-	$	45.0
Redeemable Serial Preferred
ACE	$100 per share par value, 4.00% - 5.00%	$100 - $105.5	62,305	62,305			6.2		6.2
DPL	$100 per share par value,      3.70% - 5.00%      6.75% (3)	$103 - $105 $100	181,698 35,000	181,698 35,000			18.2  3.5		18.2  3.5
						$	27.9	$	27.9

(1)	In September and October of 2004, Pepco redeemed 81,400 and 84,502 shares, respectively, of its $2.28 Series 1965 Serial Preferred Stock at an aggregate redemption of $4.1 million and $4.2 million, respectively.
(2)	The shares of Pepco's $3.40 Serial Preferred Stock Series of 1992 were subject to mandatory redemption, at par, through the operation of a sinking fund that began redeeming 50,000 shares annually, on September 1, 2002, with all then outstanding shares to be redeemed by September 1, 2007. The shares were not redeemable prior to September 1, 2002; thereafter, the shares were redeemable at par. On September 2, 2003, Pepco redeemed $2.5 million or 50,000 shares of its $3.40 Serial Preferred Stock Series of 1992 pursuant to mandatory sinking fund provisions. In September 2004, Pepco redeemed $2.5 million or 50,000 shares of its $3.40 Serial Preferred Stock Series of 1992 pursuant to mandatory sinking fund provisions. In December 2004, Pepco repurchased all of the 850,000 shares of the series remaining outstanding at par or an aggregate of $42.5 million.
(3)	Redeemable as of November 1, 2003 at $100 per share.

(10)  STOCK BASED COMPENSATION, DIVIDEND RESTRICTIONS, AND CALCULATIONS OF
        EARNINGS PER SHARE OF COMMON STOCK

Stock Based Compensation

     PHI maintains a Long-Term Incentive Plan (the LTIP), the objective of which is to increase shareholder value by providing a long-term incentive to

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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 the Board 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, and dividend equivalents. Up to 10,000,000 shares of common stock initially were available for issuance under the LTIP over a period of 10 years commencing August 1, 2002.

     Prior to acquisition of Conectiv by Pepco, each company had a long-term incentive plan under which stock options were granted. At the time of the acquisition, certain Conectiv options vested and were canceled in exchange for a cash payment. Certain other Conectiv options were exchanged on a 1 for 1.28205 basis for Pepco Holdings stock options under the LTIP: 590,198 Conectiv stock options were converted into 756,660 Pepco Holdings stock options. The Conectiv stock options were originally granted on January 1, 1998, January 1, 1999, July 1, 1999, October 18, 2000, and January 1, 2002, in each case with an exercise price equal to the market price (fair value) of the Conectiv stock on the date of the grant. The exercise prices of these options, after adjustment to give effect to the conversion ratio of Conectiv stock for Pepco Holdings stock, are $17.81, $18.91, $19.30, $13.08 and $19.03, respectively. All of the Pepco Holdings options rece ived in exchange for the Conectiv options granted in 1998, 1999, 2000 and 50 percent of the options exchanged for options granted in 2002 are exercisable. The remaining Pepco Holdings options received in exchange for options granted in 2002 became exercisable on January 1, 2005.

     At the time of the merger, outstanding Pepco options were exchanged on a one-for-one basis for Pepco Holdings stock options granted under the LTIP. The options were originally granted under Pepco's long-term incentive plan in May 1998, May 1999, January 2000, May 2000, January 2001, May 2001, January 2002, and May 2002. The exercise prices of the options are $24.3125, $29.78125, $22.4375, $23.15625, $24.59, $21.825, $22.57 and $22.685, respectively, which represent the market prices (fair values) of the Pepco common stock on its original grant dates. All the options granted in May 1998, May 1999, January 2000, and May 2000 are exercisable. Seventy-five percent of the options granted on January 1, 2001 are exercisable and the remaining options became exercisable on January 1, 2005. Seventy-five percent of the options granted on May 1, 2001 are exercisable and the remaining options will become exercisable on May 1, 2005. 50% of the options gra nted on January 1, 2002 are exercisable. Twenty-five percent of the remaining options granted on January 1, 2002 became exercisable on January 1, 2005 and twenty-five percent will become exercisable on January 1, 2006. 50% of the options granted on May 1, 2002 are exercisable. The remaining options granted on May 1, 2002 will become exercisable at the rate of twenty-five percent on May 1, 2005 and 2006.

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     Stock option activity for the three years ended December 31 is summarized below. The information presented in the table is for Pepco Holdings, including converted Pepco and Conectiv options.

	2004			2003			2002
	Number of Shares		Weighted AveragePrice	Number of Shares		Weighted AveragePrice	Number of Shares		Weighted AveragePrice
Beginning-of-year   balance	2,115,037	$	21.8131	2,122,601	$	21.8031	970,741	$	23.7810
Options granted	--	$	--	--	$	--	1,151,860	$	20.1363
Options exercised	41,668	$	18.9385	--	$	--	--	$	--
Options forfeited	9,615	$	19.0300	7,564	$	19.0300	--	$	--
End-of-year balance	2,063,754	$	21.8841	2,115,037	$	21.8131	2,122,601	$	21.8031
Exercisable at end   of year	1,739,032	$	21.9944	1,211,448	$	22.8386	863,973	$	20.3969

     As of December 31, 2004, an analysis of options outstanding by exercise prices is as follows:

Range of Exercise Prices	Number Outstanding At December 31, 2004	Weighted Average Exercise Price	Weighted Average Remaining ContractualLife
$13.08 to $19.30	697,813	18.8552	7.2
$21.83 to $29.78	1,365,941	23.4314	5.6
	2,063,754	21.8841	6.1

     Pepco Holdings recognizes compensation costs for the LTIP based on the accounting prescribed by APB No. 25, "Accounting for Stock Issued to Employees." There were no stock-based employee compensation costs charged to expense in 2004, 2003 and 2002 in respect to stock options granted under the LTIP.

     There were no options granted in 2004 or 2003. The fair values of options granted in 2002, estimated on the date of grant using the Black-Scholes option pricing model, and related valuation assumptions are as follows:

	2002
Weighted average fair value per option	$ 3.59
Expected option term (years)	8
Expected volatility	27.43%
Expected dividend yield	5.40%
Risk-free interest rate	5.20%

     The weighted-average fair value of options granted during 2002 was $22.57 per share.

     The Performance Restricted Stock Program and the Merger Integration Success Program have been established under the LTIP. Under the Performance Restricted Stock Program, performance criteria are selected and measured over a three-year period. The target number of share award opportunities established in 2001 under Pepco's Performance Restricted Stock Program, a component of Pepco Holdings' LTIP, for performance periods 2002-2004 was 57,000. The target number of share award opportunities established in 2004, 2003 and 2002 under Pepco Holdings' Performance Restricted Stock Program for performance periods 2005-2007, 2004-2006 and 2003-2005 were 247,400, 292,100 and 287,800, respectively. The fair value per share on award date for the performance restricted stock was $21.060 for the 2005-2007 award, $19.695 for the 2004-2006 award, $19.405 for the 2003-2005 award and $22.51 for the 2002-

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2004 award. Depending on the extent to which the performance criteria are satisfied, the executives are eligible to earn shares of common stock under the Performance Restricted Stock Program ranging from 0% to 200% of the target share award opportunities. No awards were earned in respect to the 2002-2004 share award opportunity.

     The maximum number of share award opportunities granted under the Merger Integration Success Program established under Pepco Holdings' LTIP during 2002 was 241,075. The fair value per share on grant date was $19.735. Of those shares, 96,427 were restricted and have time-based vesting over three years: 20% vested in 2003, 30% vested in 2004, and 50% will vest in 2005. The remaining 144,648 shares are performance-based award opportunities that may be earned based on the extent to which operating efficiencies and expense reduction goals are attained through December 31, 2003 and 2004, respectively. Although the goals were met in 2003, it was determined that 63,943 shares, including shares reallocated from participants who did not meet performance goals as well as shares reflecting accrued dividends for the period August 1, 2002 to December 31, 2003, granted to certain executives, would not vest until 2005, and then only if the co st reduction goals were maintained and Pepco Holdings' financial performance is satisfactory. 9,277 shares of common stock vested under this program on December 31, 2003 for other eligible employees. On March 11, 2005, 70,315 shares, including reinvested dividends, vested for the performance period ending on December 31, 2004.

     Under the Pepco Holdings, Inc. Long-Term Incentive Plan, non-employee directors are entitled to a grant on May 1 of each year of a non-qualified stock option for 1,000 shares of common stock. However, the Board of Directors has determined that these grants will not be made.

     On August 1, 2002, the date of the consummation of Pepco's merger with Conectiv, in accordance with the terms of the merger agreement, 80,602 shares of Conectiv performance accelerated restricted stock (PARS) were converted to 103,336 shares of Pepco Holdings restricted stock. The PARS were originally granted on January 1, 2002 at a fair market price of $24.40. All of the converted restricted stock has time-based vesting over periods ranging from 5 to 7 years from the original grant date.

     In June 2003, the President and Chief Executive Officer of PHI received a retention award in the form of 14,822 shares of restricted stock. The shares will vest on June 1, 2006, if he is continuously employed by Pepco Holdings through that date.

Dividend Restrictions

     Under PUHCA, PHI is prohibited, without SEC approval, from paying dividends on its common stock from capital or unearned surplus. PHI generates no operating income of its own. Accordingly, its ability to pay dividends to its shareholders depends on dividends received from its subsidiaries. In addition to their future financial performance, the ability of PHI's direct and indirect subsidiaries to pay dividends is subject to limits imposed by: (i) state corporate and regulatory laws, which impose limitations on the funds that can be used to pay dividends and, in the case of regulatory laws, as applicable, may require the prior approval of the relevant utility regulatory commissions before dividends can be paid; (ii) PUHCA, which prohibits a subsidiary of a registered public utility holding company from paying a dividend out of capital or unearned surplus without the prior approval of the SEC; (iii) the prior rights of holders of existing and futu re preferred stock, mortgage bonds and other long-term debt issued by the subsidiaries, and any

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other restrictions imposed in connection with the incurrence of liabilities, and (iv) certain provisions of the charters of Pepco, DPL and ACE, which impose restrictions on payment of common stock dividends for the benefit of preferred stockholders.

Calculations of Earnings Per Share of Common Stock

     Reconciliations of the numerator and denominator for basic and diluted earnings per share of common stock are shown below.

		For the Year Ended December 31,
			2004		2003		2002
			(Millions, except Per Share Data)
Income (Numerator):
Net Income		$	258.7	$	113.5	$	210.5
Add:    Redemption of subsidiary's           Preferred Stock			.5		-		-
Earnings Applicable to Common Stock		$	259.2	$	113.5	$	210.5
Shares (Denominator)(a):
Average shares outstanding for computation of   basic earnings per share of common stock			176.8		170.7		131.1	(b)
Average shares outstanding for diluted   computation:
Average shares outstanding			176.8		170.7		131.1
Adjustment to shares outstanding			-		-		-
Average Shares Outstanding for Computation of   Diluted Earnings Per Share of Common Stock			176.8		170.7		131.1
Basic earnings per share of common stock		$	1.47	$	.66	$	1.61
Diluted earnings per share of common stock		$	1.47	$	.66	$	1.61
(a)	Options to purchase shares of common stock that were excluded from the calculation of diluted EPS as they are considered to be anti-dilutive were approximately 1.4 million, 2.0 million, and 1.4 million for the years ended December 31, 2004, 2003, and 2002, respectively.
(b)	Amount includes weighted average impact of 56.2 million Pepco Holdings shares issued to Conectiv shareholders on August 1, 2002 in connection with the acquisition of Conectiv.

     The Company's Shareholder Dividend Reinvestment Plan (DRP) provides that shares of common stock purchased through the DRP may be original issue shares or, at the option of Pepco Holdings, shares purchased in the open market. The DRP permits additional cash investments by DRP participants of not less than $25 each calendar month or more than $200,000 each calendar year. There were 1,471,936, 1,706,422 and 629,777 original issue shares issued under the DRP in 2004, 2003 and 2002, respectively.

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     The following table presents Pepco Holdings' common stock reserved and unissued at December 31, 2004:

Name of Plan	Number of  Shares
DRP	1,174,629
Conectiv Incentive Compensation Plan	1,758,332
Potomac Electric Power Company Long-Term Incentive Plan	1,400,000
Pepco Holdings, Inc. Long-Term Incentive Plan	9,743,464
Pepco Holdings, Inc. Stock Compensation Plan for Directors	95,825
Pepco Holdings, Inc. Non-Management Directors Compensation Plan	500,000
Potomac Electric Power Company Savings Plans consisting of (i)   the Savings Plan for Exempt Employees, (ii) the Savings Plan   for Bargaining Unit Employees, and (iii) the Savings Plan for   Non-Exempt, Non-Bargaining Unit Employees	2,450,840
Conectiv Savings and Investment Plan	14,894
Atlantic Electric Savings and Investment Plan-B	22,937
Total	17,160,921

(11)  FAIR VALUE OF FINANCIAL INSTRUMENTS

     The estimated fair values of Pepco Holdings' financial instruments at December 31, 2004 and 2003 are shown below.

		At December 31,
		2004			2003
		(Millions of Dollars)
		Carrying  Amount	Fair Value		Carrying  Amount	Fair Value
Assets
Marketable securities	$	-	$      -	$	23.0	$   23.0
Liabilities and Capitalization
Long-Term Debt	$	4,362.1	$4,575.3	$	4,588.9	$4,920.3
Transition Bonds issued by ACE Funding	$	523.3	$  537.5	$	551.3	$  583.1
Long-Term Project Funding	$	65.3	$   65.3	$	68.6	$   68.6
Debentures issued to Financing Trust     (short-term)	$	-	$      -	$	25.8	$   25.8
Debentures issued to Financing Trust	$	-	$      -	$	72.2	$   70.8
Serial Preferred Stock	$	27.0	$   21.7	$	35.3	$   26.9
Redeemable Serial Preferred Stock	$	27.9	$   18.7	$	27.9	$   19.0
Mandatorily Redeemable Serial     Preferred Stock	$	-	$      -	$	45.0	$   45.1

     The methods and assumptions below were used to estimate, at December 31, 2004 and 2003, the fair value of each class of financial instruments shown above for which it is practicable to estimate that value.

     The fair value of the Marketable Securities was derived based on quoted market prices.

     The fair values of the Long-term Debt, which includes First Mortgage Bonds and Medium-Term Notes, excluding amounts due within one year, were derived based on current market prices, or for issues with no market price available, were based on discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The fair values of the Recourse and the Non-Recourse Debt held by PCI, excluding amounts due within one year, were based on current rates offered to similar companies for debt with similar remaining maturities.

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

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

(12)  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., pursuant to an Asset Purchase and Sale Agreement. As part of the Asset Purchase and Sale Agreement, Pepco entered into several ongoing contractual arrangements with Mirant 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).

     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 currently 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 have arisen or 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 standard offer service obligations in Maryland through June 2004 and its standard offer service 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 that Pepco believes are liable to Pepco under the terms of the Asset Purchase and Sale Agreement's Assignment and Assumption Agreement (the Assignment

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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 current plan of reorganization filed by the Mirant entities with the Bankruptcy Court, certain Mirant entities other than Mirant Corporation would pay significantly higher portions 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 an agreement with Panda, entered into in 1991, Pepco is obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (the Panda PPA). 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 Oblig ations).

     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 which 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 this uncertainty, Pepco, in the third quarter of 2003, expen sed $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 amou nt ultimately recovered could be higher or lower.

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     Mirant's Attempt to Reject the PPA-Related Obligations

     On August 28, 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). On August 4, 2004, the Court of Appeals remanded the case to the District Court saying that the District Court has jurisdiction to rule on the merits of Mirant's rejection motion, suggesting that in doing so the court apply a "more ri gorous standard" than the business judgment 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 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, 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.

     As more fully discussed below, Mirant had been making regular periodic payments in respect of the PPA-Related Obligations. On December 9, 2004, Mirant filed a notice with the Bankruptcy Court that it was suspending payments to Pepco in respect of the PPA-Related Obligations. On December 13, 2004, Mirant failed to make a payment of approximately $17.9 million due to Pepco for the period November 1, 2004 to November 30, 2004. Mirant failed to make that payment. On December 23, 2004, Pepco received a payment of approximately $6.8 million from Mirant, which according to Mirant represented the market value of the power for which payment was due on December 13. Mirant has informed Pepco that it intends to continue to pay the market value, but not the above-market portion, of the power purchased under the PPA-Related Obligations. Pepco disagrees with Mirant's assertion that it need only pay the market value and believes that the amount repr esenting the market value calculated by Mirant is insufficient.

     On January 21, 2005, Mirant made a approximately $21.1 million, which, according to Mirant, includes the payment for the FirstEnergy PPA for December 2004 and "includes the December 2004 TPA revenue in the amount of $29,093,173.43, the TPA costs in the amount of $37,865,924.10, and an allocated share of [FirstEnergy's] PPA bill credits/charges in the amount of $5,490,164.79." Pepco disputes Mirant's contention that the amount paid reflects the full amount due Pepco under these agreements for the applicable periods.

     As of March 1, 2005, Mirant has withheld payment of approximately $34.8 million due to Pepco under 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. On March 1, 2005 (as amended by order dated March 7, 2005), the District Court granted Pepco's motion to withdraw jurisdiction over the Asset Purchase and Sale Agreement

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rejection proceedings from the Bankruptcy Court. In addition, the District Court ordered Mirant to pay on March 18, 2005, all past-due unpaid amounts under the PPA-Related Obligations. Mirant has filed a motion for reconsideration and a stay of the March 1, 2005 order.

     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 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 $133.2 million as of March 1, 2005 (assuming Mirant continues to withhold unpaid amounts of approximately $34.8 million as of March 1, 2005.

     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 March 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 March 1, 2005, at the rates provided in the PPA (with an average price per kilowatt hour of approximately 6.0 cents) and resold the capacity and energy at market rates projected, given the characteristics of the FirstEnergy PPA, to be approximately

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5.0 cents per kilowatt hour, Pepco estimates that it would cost approximately $31 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 March 1, 2005, at the rates provided in the PPA (with an average price per kilowatt hour of approximately 16.9 cents), and resold the capacity and energy at market rates projected, given the characteristics of the Panda PPA, to be approximately 7.4 cents per kilowatt hour, Pepco estimates that it would cost approximately $29 million for the remainder of 2005, approximately $34 million in 2006 and 2007, and approximately $34 million to $49 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.

     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 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 distribution rates. If Pe pco'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. However, the accounting treatment of such a loss depends on a number of legal and regulatory factors, and is not determinable at this time.

     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

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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.

     On March 15, 2004, Mirant filed a complaint with the Bankruptcy Court seeking a declaratory judgment that the facility and capacity credit 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.

Federal Tax Treatment of cross-border Leases

     PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which as of December 31, 2004 had a book value of approximately $1.2 billion. 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 that the IRS intends to challenge on various grounds the purported tax benefits claimed by taxpayers enteri ng into certain sale-leaseback transactions with tax indifferent parties, including those entered into on or prior to March 12, 2004 (the Notice).

     PCI's cross-border energy leases are similar to those sale-leaseback transactions described in the Notice. PCI's leases are currently under examination by the IRS as part of the normal PHI tax audit. PHI believes there is a substantial likelihood that the IRS will challenge the tax benefits realized from interest and depreciation deductions claimed by PCI with respect to these leases, or the timing of these benefits, for the years 2001 through 2004. The tax benefits claimed by PCI for these years were approximately $175 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 deferral of tax benefits that does not change the total estimated net income from PHI's leases does not require an adjustment to the book value of the leases. 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.

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     In recent deliberations, The Financial Accounting Standards Board (FASB) has determined that a change in the timing of tax benefits also should require a repricing of the lease and an adjustment to the book value of a lease. Under this interpretation, 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. PHI understands that the FASB intends to publish this guidance for comment in the near future to become effective at the end of 2005. If adopted, the application of this guidance could result in a material adverse effect on PHI's results of operations even if the resolution is limited to a deferral of the tax benefits realized by PCI from its leases.

Rate Proceedings

     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. The petition was based on actual data for the nine months ended September 30, 2002, and forecasted data for the three months ended December 31, 2002 and sought an overall rate increase of approximately $68.4 million, consisting of an approximately $63.4 million increase in electricity distribution rates and $5 million for recovery of regulatory assets through the RARC. In October 2003, ACE filed an update supporting an overall rate increase of approximately $41.3 million, consisting of a $36.8 million increase in electricity distribution rates and a RARC of $4.5 million. This petition was ACE's first increase request for electric distribution rates since 1991. The requested increase would apply to all rate schedules in ACE's tariff. The Ratepayer Advocate filed testimony on January  3, 2004, proposing an annual rate decrease of $11.7 million. Intervenor groups representing industrial users and local generators filed testimony that did not take a position with respect to an overall rate change but their proposals, if implemented, would affect the way in which an overall rate increase or decrease would be applied to the particular rates under which they receive service. ACE's rebuttal testimony, filed in February 2004, made some changes to its October filing and proposed an overall rate increase of approximately $35.1 million, consisting of a $30.6 million increase in distribution rates and a $4.5 million increase in the RARC. Hearings were held before an Administrative Law Judge in late March, early April and May 2004. At the hearing held in April 2004, the Ratepayer Advocate proposed an annual rate decrease of $4.5 million, modifying its earlier proposal that rates be decreased by $11.7 million annually. The Ratepayer Advocate and Staff of the NJBPU filed their briefs in this proceeding in August 2004. The Ratepayer Advocate's brief supported its earlier proposal of an annual rate decrease of $4.5 million. The Staff's brief, however, stated for the first time its position calling for an overall decrease of $10.8 million. Reply briefs were filed on August 23, 2004. Settlement discussions between ACE, the NJBPU Staff and the Ratepayer Advocate have been ongoing.

     On December 12, 2003, the NJBPU issued an order also consolidating outstanding issues from several other proceedings into the base rate case proceeding. On December 22, 2003, ACE filed a Motion for Reconsideration in which it suggested that these issues be dealt with in a Phase II to the base rate case to address the outstanding issues identified in the December 12, 2003 Order. After discussion with the parties to the base rate case, it was agreed that a Phase II to the base rate case to address these issues, along with the $25.4 million of deferred restructuring costs previously transferred into the base rate case, would be initiated in April 2004. On April 15, 2004, ACE filed testimony with the NJBPU initiating a Phase II to the base rate proceeding described above. The parties to this case have

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been actively engaged in settlement discussions in conjunction with settlement of Phase I issues.

     On August 31, 2004, ACE filed requests with the NJBPU proposing changes to its Transition Bond Charge, its Market Transition Charge - Tax rate, and its BGS Reconciliation charges. The net impact of these rate changes is to decrease ACE's annual revenues by approximately 1.5%. All of these rate changes were implemented on October 1, 2004.

     On October 1, 2004, DPL submitted its annual Gas Cost Rate (GCR) filing to the 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, on November 29, 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 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. A final order addressing both the Nov ember 1 and December 29 increases is expected in the spring of 2005.

     On February 13, 2004, DPL filed with the DPSC for a change in electric ancillary service rates that would have an aggregate effect of increasing annual Delaware electric revenues by $13.1 million or 2.4%. This filing was prompted by the increasing ancillary service costs charged to DPL by PJM Interconnection, LLC (PJM). The proposed rates went into effect on March 15, 2004, subject to refund. On June 22, 2004, the DPSC approved a settlement agreement that provided for an increase having an aggregate effect of increasing annual Delaware electric revenues by $12.4 million, or 2.3%, with rates effective June 23, 2004. The approved increase was slightly less than the proposed increase that went into effect on March 15, 2004. As part of the settlement, the resulting estimated over-collection of $75,000 was given by DPL to the State of Delaware Low Income Fund administered by the Delaware Department of Human Services on July 15, 2 004.

     In compliance with the settlement approved by the MPSC in connection with the merger of Pepco and Conectiv, on December 4, 2003, DPL and Pepco submitted testimony and supporting schedules to review and reset if necessary its electricity distribution rates in Maryland to be effective July 1, 2004, when the then-current distribution rate freeze/caps ended. DPL's filing demonstrated that it was in an under-earning situation and, as allowed in the merger settlement, DPL requested that a temporary rate reduction implemented on July 1, 2003 for non-residential customers be terminated effective July 1, 2004. DPL estimated that the termination of the rate reduction would increase its annual revenues by approximately $1.1 million. A settlement reached between the parties allowing for this $1.1 million increase to be effective July 1, 2004 was approved by the MPSC in Order No. 79186. With limited exceptions, DPL cannot increase its distribution rates until January 1, 2007.

     Pepco's filing demonstrated that it also was in an under-earning situation. However the merger settlement provided that Pepco's distribution rates after July 1, 2004 could only remain the same or be decreased. With limited exceptions, Pepco cannot increase its distribution rates until January 1, 2007. In an order dated July 6, 2004 the MPSC affirmed the

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Hearing Examiner's recommendation that no rate decrease was warranted at that time.

     On July 3, 2004, Pepco filed a distribution rate review case with the DCPSC as required by the terms of the Pepco-Conectiv merger settlement approved by the DCPSC. This case will determine whether Pepco's distribution rates will be decreased. In accordance with the terms of the merger settlement, Pepco's distribution rates cannot be increased as a result of the case. On November 24, 2004, the DCPSC issued an order that designated the issues to be considered in the case and set the hearing schedule. On December 17, 2004, Pepco filed supplemental direct testimony addressing the DCPSC-designated issues. Pepco's filings indicate that no rate decrease is warranted. On March 4, 2005, the DCPSC issued an order granting a joint motion filed on March 3, 2005, on behalf of Pepco and several other parties in the case to suspend the procedural schedule to allow the parties to focus on completing settlement discussions. In the joint motion, the movin g parties informed the DCPSC that they had agreed in principle to settlement provisions that would resolve all issues in the proceeding and that a settlement agreement could be filed in the near future.

Restructuring Deferral

     Pursuant to a July 1999 summary order issued by the NJBPU under the New Jersey Electric Discount and Energy Competition Act (EDECA) (which was subsequently affirmed by a final decision and order issued in March 2001), ACE was obligated to provide basic generation service (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 Ener gy Adjustment Clause and ACE's Demand Side Management Programs. ACE established a regulatory asset in an amount equal to the balance.

     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.

     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) transferred to ACE's 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

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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 Appellate Division of the Superior Court of New Jersey, which hears appeals of New Jersey administrative agencies, including the NJBPU, a Notice of Appeal related to the July 2004 final order. 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 on July 31, 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. 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. On March 4, 2003, theInternal Revenue S ervice (IRS) issued a notice of proposed rulemaking (NOPR)that is relevant to that principal issue.Comments on the NOPR were filed byseveral parties on June 2, 2003, and the IRS held a public hearing on June 25,2003.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 thecourts have held and the IRS has stated that proposed rules are notauthoritative and that no decision should be issued on the basis of proposedrules. Instead, Pepco argued that the only prudent course of action is for the DCPSC to await the issuance of final regulations relating to the taxissues and then 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 adoptregulations. Other issues in the proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.

     Pepco believes that a sharing of EDIT and ADITC would violate the 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 ADITC balance, 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 December 31, 2004, the District of Columbia jurisdictional transmission and distribution-related ADITC balance was approximately $6.0 million.

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     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 D.C. 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. Reply briefs were filed in May 2002. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that was raised in the D.C. case. As of December 31, 2004, 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, 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 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 operative. As of December 31, 2004, the Maryland retail jurisdiction al transmission and distribution-related ADITC balance was approximately $10.7 million. The Hearing Examiner decided all other issues in favor of Pepco, except 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 4, 2003 IRS NOPR.

     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

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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 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.

SOS and Default Service Proceedings

     District of Columbia

     In February 2003, the DCPSC opened a new proceeding to consider issues relating to (a) the establishment of terms and conditions for providing SOS in the District of Columbia after Pepco's obligation to provide SOS terminated on February 7, 2005, and (b) the selection of a new SOS provider.

     In December 2003, the DCPSC issued an order that set forth the terms and conditions for the selection of a new SOS provider(s) and the provision of SOS by Pepco on a contingency basis. In December 2003, the DCPSC also issued an order adopting terms and conditions that would apply if Pepco continued as the SOS provider after February 7, 2005. In March 2004, the DCPSC issued an order adopting the wholesale SOS model,i.e., Pepco would continue to be the SOS provider in the District of Columbia after February 7, 2005. This March 2004 order, as amended by a DCPSC order issued in July 2004, extends Pepco's obligation to provide default electricity supply at market rates for up to an additional 76 months for small commercial and residential customers, and for an additional 28 months for large commercial customers.

     In August 2004, the DCPSC issued an order adopting administrative charges for residential, small and large commercial DC SOS customers that are intended to allow Pepco to recover the administrative costs incurred to provide the SOS supply. The approved administrative charges include an average margin for Pepco of approximately $0.00248 per kilowatt hour, calculated based on total sales to residential, small and large commercial DC SOS customers over the twelve months ended December 31, 2003. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of DC SOS customers from each customer class and the load taken by such customers over the time period. The administrative charges went into effect for Pepco's DC SOS sales on February 8, 2005. Pepco completed the first competitive procurement process for DC SOS at the end of October and filed the proposed new SOS rates with the DC PSC on November 3, 2004.

     The TPA with Mirant under which Pepco obtained the fixed-rate DC 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 DC 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 DC SOS rates charged to customers during the period from January 23 through January 31, 2005. In addition, because the new DC 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 DC SOS contracts and the DC SOS rates charged to customers for the period from February 1 to February 7, 2005. The total amount of the diff erence is estimated to be approximately $8.7 million. This difference, however, will

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be included in the calculation of the Generation Procurement Credit (GPC) for DC 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 recovery 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.

     Maryland

     Under a settlement approved by the MPSC in April 2003 addressing SOS service in Maryland following the expiration of Pepco's fixed-rate default supply obligations in July 2004, Pepco is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customers through May 2006, and to large commercial customers through May 2005. In accordance with the settlement, Pepco purchases the power supply required to satisfy its market rate default supply obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved by the MPSC. Pepco is entitled to recover from its default supply customers the cost of the default supply plus an average margin of $0.002 per kilowatt hour, calculated based on total sales to residential, small and large commercial Maryland SOS customers over the twelve months ended December 31, 200 3. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of Maryland SOS customers from each customer class and the load taken by such customers over the time period.

     Under a settlement approved by the MPSC in April 2003 addressing SOS service in Maryland following the expiration of DPL's fixed-rate default supply obligations to non-residential customers in June 2004 and to residential customers through June 2004, DPL is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customers through May 2006, and to large commercial customers through May 2005. In accordance with the settlement, DPL purchases the power supply required to satisfy its market rate default supply obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved and supervised by the MPSC. DPL is entitled to recover from its default supply customers the costs of the default supply plus an average margin of $0.002 per kilowatt hour, calculated based on total sales to residential, small, and large commercial Maryland SOS customers over the twelve months ended December 31, 2003. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of Maryland SOS customers from each customer class and the load taken by such customers over the time period.

     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 VSCC. DPL currently obtains all of the energy and capacity needed to fulfill its default service obligations in Virginia under a supply

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agreement with Conectiv Energy. A prior agreement, also with Conectiv Energy, terminated effective December 31, 2004. The current contract was entered into after conducting a competitive bid procedure identical to the Maryland SOS process in most respects and Conectiv Energy was the lowest bidder to provide wholesale power supply for DPL's Virginia default service customers. The new supply agreement commenced January 1, 2005 and expires in May 2006. On October 26, 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 dated November 17, 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 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 17 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 Office of Attorney General. The VSCC ruled on January 18, 2005, that the administrative charge and margin are base rate items not recoverable through a fuel clause. No appeal is planned regarding this filing. A settlement resolving all other issues and m aking the interim rates final was filed on March 4, 2005, contingent only on possible future adjustment depending on the result of a related proceeding at FERC. A hearing is scheduled for March 16, 2005, and the VSCC is expected to approve the settlement.

     Also in October, DPL and Conectiv Energy jointly filed an application with the VSCC under Virginia's Affiliates Act requesting authorization for DPL to enter into a contract to purchase power from an affiliate. This authorization permits the contract to be executed with an affiliate, but is not a ruling on the merits of the contract. A VSCC order dated December 17, 2004 granted approval for DPL to purchase power from Conectiv Energy under the new contract according to its terms beginning January 1, 2005.

     On October 29, 2004, Conectiv Energy made a filing with FERC requesting authorization to enter into a contract to supply power to an affiliate. On December 30, 2004, FERC granted the requested authorization effective January 1, 2005, subject to refund and hearings on the narrow question whether, in 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 unduly favored Conectiv Energy in the credit criteria and analysis applied. DPL cannot predict the outcome of this proceeding.

     Delaware

     Under a settlement approved by the DPSC, DPL is required to provide default electricity supply to customers in Delaware until May 1, 2006. On October 19, 2004, the DPSC initiated a proceeding to investigate and determine which entity should act as the standard offer supplier in DPL's Delaware service territory after May 1, 2006, and what prices should be charged for SOS after May 1, 2006. Similar to the process used in Maryland, 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 will resolve issues relating to the process under which supply will be

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acquired by the SOS provider and way in which SOS prices will be set and monitored. In the last stage, 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 February 22, 2005, the DPSC voted to approve an SOS process that will allow a Wholesale Standard Offer Service Model with DPL as the SOS Provider. Issues including the length of this extension and any profit margin that DPL may be able to earn and retain in conjunction with this service have been deferred for further discussion and will be decided by the DPSC at a later date. A written DPSC order documenting this decision is expected sometime in March or April 2005.

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

     Pursuant to a September 25, 2003 NJBPU order, ACE filed a report on April 30, 2004 with the NJBPU recommending that the B.L. England generating facility be shut down in accordance with the terms of an April 26, 2004 preliminary settlement agreement among PHI, Conectiv and ACE, New Jersey Department of Environmental Protection (NJDEP) and the Attorney General of New Jersey. The report stated that the operation of the B.L. England facility is necessary at the present time to satisfy reliability standards, but that those reliability standards could also be satisfied in other ways. The report concludes 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 lines into southern New Jersey. ACE cannot predict wh ether the NJBPU will approve the construction of the additional transmission lines.

     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 the transmission upgrades necessary to maintain reliability in the Atlantic zone after the retirement of B.L. England. 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 re cover 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 FERC and the state regulatory commissions and, therefore, cannot predict the financial impact to ACE of installing the recommended transmission upgrades. However, in the event that the NJBPU makes satisfactory findings and grants other requested approvals concerning the retirement of B.L. England and approves the construction of the transmission upgrades required to maintain reliability in the Atlantic zone after such retirement, 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.

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     On November 1, 2004, ACE made a filing with the NJBPU requesting approval of the transmission upgrades required to maintain reliability in the Atlantic zone after the retirement of B.L. England. On December 22, 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 cannot predict the outcome of these two proceedings.

     On November 12, 2004, ACE made a filing with the NJBPU requesting approval of year 2005 capital projects with respect to B.L. England. This filing was made pursuant the September 25, 2003 B.L. England rate order, which established a requirement that ACE file for approval of capital expenditures in excess of $1 million. For 2005, four projects, totaling $3.2 million in capital expenditures, have been identified as necessary to allow continued operation of B.L. England until its retirement. Two of these projects are well below the $1 million threshold set forth in the September 25, 2003 NJBPU order and two are above that threshold. ACE cannot predict the outcome of this proceeding.

General Litigation

     Asbestos

     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, plaintiffs argue 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

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unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco's and PHI's results of operations.

     Enron

     On December 2, 2001, Enron North America Corp. and several of its affiliates (collectively, Enron) filed for protection under the United States Bankruptcy Code. In December 2001, DPL and Conectiv Energy terminated all energy trading transactions under various agreements with Enron. In late January 2003, after several months of discussions between the parties concerning the amount owed by DPL and Conectiv Energy, Enron filed an adversary complaint against Conectiv Energy in the Bankruptcy Court for the Southern District of New York. The complaint sought, among other things, damages in the amount of approximately $11.7 million.

     On June 3, 2004, the Bankruptcy Court approved a settlement among Enron, Conectiv Energy and DPL pursuant to which Conectiv Energy paid Enron an agreed settlement amount that was less than the $11.7 million damages Enron sought and the parties released all claims against each other. Conectiv Energy had previously established a reserve in an amount equal to the agreed settlement payment. Accordingly, the settlement did not have an effect on earnings.

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 CERCLA at the Diamond State Salvage site in Wilmington, Delaware. In the context of the negotiations, DOJ informed DPL that DPL is a de minimis party at the site. In February 2005, DPL entered into a de minimis consent decree with the United States which, if approved by the U.S. District Court, would require DPL to pay $144,000 as reimbursement of the government's response costs, resolve DPL's alleged liability, and provide DPL a covenant not to sue from the United States and protection from third-party claims for contribution.

     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

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reached with the MDE. DPL expects to complete the RI/FS in the first quarter of 2005.

     In October 1995, each of Pepco and DPL received notice from EPA that it, along with several hundred other companies, might be a 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 this site. Under the terms of the consent decree, which was approved by the U.S. District Court for the District of Maryland on March 31, 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 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. On May 12, 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. On October 2, 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 December 31, 2004, Pepco had accrued $1.7 million to meet its liability for a site remedy. 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.

     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 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

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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.

     On April 7, 2000, approximately 139,000 gallons of oil leaked from a pipeline at a generating facility that was owned by Pepco at Chalk Point generating facility in Aquasco, Maryland. The pipeline was operated by Support Terminals Services Operating Partnership LP (ST Services), an unaffiliated pipeline management company. The oil spread from Swanson Creek to the Patuxent River and several of its tributaries. The area affected covers portions of 17 miles of shoreline along the Patuxent River and approximately 45 acres of marshland adjacent to the Chalk Point property.

     In December 2000, the Department of Transportation, Office of Pipeline Safety, Research and Special Programs Administration (OPS) issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (NOPV). The NOPV alleged various deficiencies in compliance with regulations related to spill reporting, operations and maintenance of the pipeline and record keeping, none of which relate to the cause of the spill. The NOPV was issued to both Pepco and ST Services and proposed a civil penalty in the amount of $674,000. On June 2, 2004, the OPS issued a Final Order regarding the NOPV in this matter. The Final Order assessed a total fine of $330,250, with $256,250 of that amount assessed jointly against Pepco and ST Services and the remaining $74,000 assessed solely against ST Services. ST Services subsequently filed a Petition for Reconsideration. All penalties were stayed pending the outcome of the Petition for Rec onsideration. On February 9, 2005, OPS issued a Decision on the Petition for Reconsideration that affirmed the Final Order. Pepco's share of the $330,250 penalty assessed pursuant to the Final Order amounts to $128,125.

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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:

· 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 emissio ns 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. Englandgenerating 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.

· 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 necessary to satisfy the EPA's new cooling water intake structure regulations in accordance with a schedule that NJDEP will establish in the renewal New Jersey Pollutant Discharge Elimination System (NJPDES) permit for the B.L. England facility. The schedule will take into account ACE's agreement, provided that all regulatory approvals are obtained, to shut down the B.L. England facility by December 15, 2007.

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· 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 also 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.

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 December 31, 2004, 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	Conectiv	PCI	Total
Energy marketing obligations of   Conectiv Energy (1)	$141.9	$ 1.6	$  -	$143.5
Energy procurement obligations   ofPepco Energy Services (1)	7.8	-	-	7.8
Standby letters of credit of   Pepco Holdings (2)	4.2	-	-	4.2
Guaranteed lease residual   values (3)	0.6	6.2	-	6.8
Loan agreement (4)	13.1	-	-	13.1
Construction performance   guarantees (5)	-	1.7	-	1.7
Other (6)	14.9	3.9	3.0	21.8
Total	$182.5	$13.4	$3.0	$198.9

1.	Pepco Holdings and Conectiv have 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 for ACE.
2.	Pepco Holdings has issued standby letters of credit of $4.2 million on behalf of subsidiary operations related to Conectiv Energy's competitive energy activities and third party construction performance. These standby letters of credit were put into place in

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	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 $4.2 million, Pepco Holdings does not expect to fund the full amount.
3.	Subsidiaries of Pepco Holdings and Conectiv have guaranteed residual values in excess of fair value related to certain equipment and fleet vehicles held through lease agreements. As of December 31, 2004, obligations under the guarantees were approximately $6.8 million. Assets leased under agreements subject to residual value guarantees are typically for periods ranging from 2 years to 10 years. Historically, payments under the guarantee 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 requiring payment under the guarantee is remote.
4.	Pepco Holdings has issued a guarantee on behalf of a subsidiary's 50% unconsolidated investment in a limited liability company for repayment of borrowings under a loan agreement of approximately $13.1 million.
5.	Conectiv has performance obligations of $1.7 million relating to obligations to third party suppliers of equipment.
6.	Other guarantees comprise:
	·	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.
	·	Conectiv has guaranteed a subsidiary building lease of $3.9 million. PHI 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 December 31, 2004, the guarantees cover the remaining $3.0 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 the agreements. Typically, claims may be made by third parties under these indemnification agreements over various periods of time depending on the nature of the claim. The maximum potential exposure under these indemnification agreements can range from a specified dollar amount to an unlimited amount depending on the nature of the claim and the particular transaction. The total maximum potential amount of future payments under these indemnification agreements is not estimable due to several factors, including uncertainty as to whether or when claims may be made under these indemnities.

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Contractual Obligations

     As of December 31, 2004, Pepco Holdings contractual obligations under power purchase agreements with non-utility generators, excluding the Panda PPA discussed above under "Relationship with Mirant Corporation," were $261.7 million in 2005, $512.7 million in 2006 to 2007 and $514.9 million in 2008 to 2009.

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

     PHI's competitive energy segments use derivative instruments primarily to reduce their financial exposure to changes in the value of their assets and obligations due to commodity price fluctuations. The derivative instruments used by the competitive energy segments include forward contracts, futures, swaps, and exchange-traded and over-the-counter options. In addition, the competitive energy segments also manage commodity risk with contracts that are not classified as derivatives. The primary goal of these activities is to manage the spread between the cost of fuel used to operate electric generation plants and the revenue received from the sale of the power produced by those plants and manage the spread between retail sales commitments and the cost of supply used to service those commitments in order to ensure stable and known minimum cash flows and fix favorable prices and margins when they become available. To a lesser extent, Conectiv Ene rgy also engages in market activities in an effort to profit from short-term geographical price differentials in electricity prices among markets. PHI collectively refers to these energy market activities, including its commodity risk management activities, as "other energy commodity" activities and identifies this activity separate from that of the discontinued proprietary trading activity described below.

     Conectiv Energy's 2003 loss includes the unfavorable impact of net trading losses of $26.6 million that resulted from a dramatic rise in natural gas futures prices during February 2003, net of an after-tax gain of $15 million on the sale of a purchase power contract in February 2003.As of March 2003, Conectiv Energy ceased all proprietary trading activities, which generally consisted of the entry into contracts to take a view of market direction, capture market price change, and put capital at risk. PHI's competitive energy segments are no longer engaged in proprietary trading; however, the market exposure under certain contracts entered into prior to cessation of proprietary trading activities was not completely eliminated because perfectly offsetting contractual positions were not available in the market at that time. These contracts will remain in place until they are terminated and their values are realized.

     On June 25, 2003, Conectiv Energy entered into an agreement consisting of a series of energy contracts with an international investment banking firm with a senior unsecured debt rating of A+ / Stable from Standard & Poors (the Counterparty). The agreement is designed to more effectively hedge approximately 50% of Conectiv Energy's generation output and approximately 50% of its supply obligations, with the intention of providing Conectiv Energy with a more predictable earnings stream during the term of the agreement. The 35-month agreement consists of two major components: a fixed price energy supply hedge and a generation off-take agreement. The fixed price energy supply hedge will be used to reduce Conectiv Energy's financial exposure under its current supply commitment to DPL. Under this commitment, which extends through May 2006, Conectiv Energy is obligated to supply to DPL the electric power necessary to enable DPL to meet its P OLR load obligations.

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Under the energy supply hedge, the volume and price risks associated with 50% of the POLR load obligation are effectively transferred from Conectiv Energy to the Counterparty through a financial "contract-for-differences." The contract-for-differences establishes a fixed cost for the energy required by Conectiv Energy to satisfy 50% of the POLR load, and any deviations of the market price from the fixed price are paid by Conectiv Energy to, or are received by Conectiv Energy from, the Counterparty. The contract does not cover the cost of capacity or ancillary services. Under the generation off-take agreement, Conectiv Energy will receive a fixed monthly payment from the Counterparty and the Counterparty will receive the profit realized from the sale of approximately 50% of the electricity generated by Conectiv Energy's plants (excluding the Edge Moor facility). This portion of the agreement is designed to hedge sales of approximately 50% of Conectiv Energy's gener ation output, and under assumed operating parameters and market conditions should effectively transfer this portion of Conectiv Energy's wholesale energy market risk to the Counterparty, while providing a more stable stream of revenues to Conectiv Energy. The 35-month agreement also includes several standard energy price swaps under which Conectiv Energy has locked in a sales price for approximately 50% of the output from its Edge Moor facility and has financially hedged other on-peak and off-peak energy price exposures in its portfolio to further reduce market price exposure. In total, the transaction is expected to improve Conectiv Energy's risk profile by providing hedges that are tailored to the characteristics of its generation fleet and its POLR supply obligation.

     PHI and its subsidiaries also use derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt incurred in connection with the operation of their business. In June 2002, PHI entered into several treasury lock transactions in anticipation of the issuance of several series of fixed rate debt commencing in July 2002. Based on this transaction, there remained a loss balance of $47.1 million in Accumulated Other Comprehensive Income (AOCI) at December 31, 2004. The portion expected to be reclassified to earnings during the next 12 months is $7.2 million. In addition, interest rate swaps have been executed in support of PCI's medium-term note program.

     The table below provides detail on effective cash flow hedges under SFAS 133 included in PHI's consolidated balance sheet as of December 31, 2004. Under SFAS 133, cash flow hedges are marked-to-market on the balance sheet with corresponding adjustments to AOCI. 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 Accumulated Other Comprehensive Loss As of December 31, 2004 (Dollars in Millions)
Contracts		Accumulated OCI    (Loss) After Tax (1)	Portion Expected to be Reclassified to Earnings during the Next 12 Months	Maximum Term
Other Energy Commodity		$  (.5)	$ 5.3	37 months
Interest Rate		(47.4)	(7.4)	332 months
Total		$(47.9)	$(2.1)
(1)	Accumulated Other Comprehensive Loss as of December 31, 2004, 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.

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     The following table shows, in millions of dollars, the pre-tax gain or (loss) recognized in earnings for cash flow hedge ineffectiveness for the years ended December 31, 2004, 2003, and 2002 and where they were reported in PHI's Consolidated Statements of Earnings during the period.

	2004	2003	2002
Operating Revenue	$ 2.5	$ 1.8	$ (.02)
Fuel and Purchased Energy	(8.5)	(2.8)	-
Total	$(6.0)	$(1.0)	$ (.02)

     For the year ended December 31, 2004, net losses totaling $6.6 million ($4.3 million after-tax) and for the year ended 2003, net gains totaling $6.8 million ($4.1 million after-tax) were reclassified out of other comprehensive income to earnings because the forecasted hedged transactions were deemed 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 years ended December 31, 2004, 2003, and 2002.

	2004	2003	2002
Proprietary Trading	$ (.4)	$(67.3)	$12.0
Other Energy Commodity	21.8	19.6	(.3)
Total	$21.4	$(47.7)	$11.7

(14)  2003 EXTRAORDINARY ITEM

     In July 2003, the New Jersey Board of Public Utilities (NJBPU) approved the determination of stranded costs related to ACE's January 31, 2003, petition relating to its B.L. England generating facility. The NJBPU approved recovery of $149.5 million. As a result of the order, ACE reversed $10.0 million of accruals for the possible disallowances related to these stranded costs. The credit to income of $5.9 million is classified as an extraordinary gain in Pepco Holdings' 2003 financial statements, since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.

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(15)  QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

     The quarterly data presented below reflect all adjustments necessary in the opinion of management for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations, differences between summer and winter rates, and the scheduled downtime and maintenance of electric generating units. The totals of the four quarterly basic and diluted earnings per common share may not equal the basic and diluted earnings per common share for the year due to changes in the number of common shares outstanding during the year.

		2004
		FirstQuarter			SecondQuarter			ThirdQuarter			FourthQuarter			Total
	(Millions of Dollars, except Per Share Data)
Total Operating Revenue	$	1,764.1		$	1,691.5		$	2,046.5		$	1,719.7		$	7,221.8
Total Operating Expenses		1,613.6			1,461.0	(d)		1,767.0			1,604.5			6,446.1
Operating Income		150.5			230.5			279.5			115.2			775.7
Other Expenses		(87.2	)		(80.6	)		(96.3	)(c)		(76.9	)		(341.0)
Preferred Stock Dividend   Requirements of   Subsidiaries		.7			.8			.7			.6			2.8
Income Before Income   Tax Expense		62.6			149.1			182.5			37.7			431.9
Income Tax Expense		11.4	(a)		58.7			71.5			31.6	(e)		173.2
Net Income		51.2			90.4	(b)		111.0			6.1			258.7
Basic and Diluted   Earnings Per Share of   Common Stock		.30			.53			.64			.03			1.47
Cash Dividends Per   Common Share	$	.25		$	.25		$	.25		$	.25		$	1.00

		2003
		FirstQuarter			SecondQuarter			ThirdQuarter			FourthQuarter			Total
	(Millions of Dollars, except Per Share Data)
Total Operating Revenue	$	1,928.7		$	1,698.4		$	2,130.6		$	1,513.6		$	7,271.3
Total Operating Expenses		1,889.6			1,559.1			1,782.0	(j)		1,424.2			6,654.9
Operating Income		39.1			139.3			348.6			89.4			616.4
Other Expenses		(79.4	)		(76.0	)		(89.1	)		(184.5	)		(429.0)
Preferred Stock Dividend   Requirements of   Subsidiaries		6.6			5.8			0.7			0.8			13.9
(Loss) Income Before   Income Tax Expense		(46.9	)		57.5			258.8			(95.9	)		173.5
Income Tax (Benefit) Expense		(22.0	)		20.4			101.5			(34.0	)		65.9
(Loss) Income Before   Extraordinary Item		(24.9	)		37.1			157.3			(61.9	)		107.6
Extraordinary Item		-			5.9	(i)		-			-			5.9
Net (Loss) Income		(24.9	)(g)		43.0	(h)		157.3			(61.9	)(f)		113.5
Basic and Diluted (Loss)   Earnings Per Share of   Common Stock Before   Extraordinary Item		(.15	)		.22			.92			(.36	)		.63
Extraordinary Item Per   Share of Common Stock		-			.03			-			-			.03
Basic and Diluted (Loss)   Earnings Per Share of   Common Stock		(.15	)		.25			.92			(.36	)		.66
Cash Dividends Per   Common Share	$	.25		$	.25		$	.25		$	.25		$	1.00

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(a)	Includes tax benefit of $13.2 million related to a local jurisdiction's final consolidated tax return regulations, which are retroactive to 2001.
(b)	Includes an $11.2 million pre-tax impairment charge ($7.3 million after-tax) to reduce the value of the Starpower investment to $28 million. Also includes $11.2 million pre-tax ($6.6 million after-tax) from the disposition of a joint venture associated with the Vineland co-generation facility.
(c)	Includes $12.8 million pre-tax ($7.7 million after-tax) associated with the prepayment of the Bethlehem debt.
(d)	Includes a $14.7 million pre-tax ($8.6 million after-tax) gain from the condemnation settlement associated with the transfer of Vineland distribution assets.
(e)	Includes a $19.7 million charge related to a PCI non-lease financial asset tax settlement with the IRS.
(f)	Includes a non-cash impairment charge of $102.6 million pre-tax ($66.7 million after-tax) related to Pepcom's investment in Starpower. Also includes $32.8 million pre-tax ($19.4 million after-tax) related to the impairment of CT inventory at Conectiv Energy and $29.6 million pre-tax ($17.7 million after-tax) offset resulting from the associated reversal of a purchase accounting fair value adjustment.
(g)	Includes $108 million pre-tax ($64.1 million after-tax) related to the cancellation of a CT contract and a $57.9 million pre-tax ($34.6 million after-tax) offset resulting from the associated reversal of a purchase accounting fair value adjustment. Also includes $26.7 million resulting from net trading losses prior to the cessation of proprietary trading.
(h)	Includes a charge of $27.5 million pre-tax ($16.3 million after-tax) related to ACE's New Jersey deferral disallowance.
(i)	Represents the favorable impact related to ACE's accrual reversal.
(j)	Includes $14.5 million pre-tax ($8.7 million after-tax) net reserve recorded against a delinquent receivable from Mirant. Also includes a $44.7 million after-tax gain on the sale of the Edison Place office building.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors
of Potomac Electric Power Company:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Potomac Electric Power Company (a wholly owned subsidiary of Pepco Holdings, Inc.) and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2)presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial st atement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it accounts for financial instruments with characteristics of both liabilities and equity as of July 1, 2003.

PricewaterhouseCoopers LLP
Washington, DC
March 16, 2005

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POTOMAC ELECTRIC POWER COMPANY CONSOLIDATED STATEMENTS OF EARNINGS
For the Year Ended December 31,		2004		2003		2002
(Millions of Dollars)
Operating Revenue
Utility	$	1,805.9	$	1,548.0	$	1,533.9
Competitive		-		-		454.1
Total Operating Revenue		1,805.9		1,548.0		1,988.0
Operating Expenses
Fuel and purchased energy		899.3		684.1		994.7
Other operation and maintenance		272.3		238.5		316.9
Depreciation and amortization		166.3		169.8		153.3
Other taxes		248.7		206.5		198.2
Gain on sale of assets		(6.9)		-		-
Total Operating Expenses		1,579.7		1,298.9		1,663.1
Operating Income		226.2		249.1		324.9
Other Income (Expenses)
Interest and dividend income		0.1		2.8		18.1
Interest expense		(79.4)		(79.6)		(106.5)
Loss from Equity Investments		-		-		(2.1)
Other income		8.3		12.3		11.3
Other expense		(1.9)		(6.3)		(17.1)
Total Other Expenses		(72.9)		(70.8)		(96.3)
Distributions on Preferred Securities of   Subsidiary Trust		-		4.6		9.2
Income Before Income Tax Expense		153.3		173.7		219.4
Income Tax Expense		56.7		69.1		80.3
Net Income		96.6		104.6		139.1
Dividends on Preferred Stock		1.0		3.3		5.0
Earnings Available for Common Stock	$	95.6	$	101.3	$	134.1
The accompanying Notes are an integral part of these Consolidated Financial Statements. 239 _____________________________________________________________________________

POTOMAC ELECTRIC POWER COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS
For the Year Ended December 31,	2004	2003	2002
(Millions of Dollars)`
Net income	$96.6	$104.6	$139.1
Other comprehensive income (loss), net of taxes
Unrealized gains (losses) on commodity derivatives     designated as cash flows:
Unrealized holding gains       arising during period	-	-	1.1
Less: reclassification adjustment for            losses included in net earnings	-	-	(.3)
Net unrealized gains on       commodity derivatives	-	-	1.4
Realized loss on Treasury lock	-	-	(54.2)
Unrealized loss on interest rate swap     agreements designated as cash flow hedges:
Unrealized holding gains arising       during period	-	-	.4
Less: reclassification adjustment for            losses included in net earnings	-	-	(.3)
Net unrealized gains on       interest rate swaps	-	-	.7
Unrealized gains on marketable securities:
Unrealized holding gains arising       during period	-	-	3.7
Less: reclassification adjustment for            losses included in net earnings	-	-	(.4)
Net unrealized gains on marketable securities	-	-	4.1
Minimum Pension Liability Adjustment	(1.2)	-	-
Other comprehensive loss, before tax	(1.2)	-	(48.0)
Income tax benefit	(.5)	-	(19.8)
Other comprehensive loss, net of tax	(.7)	-	(28.2)
Comprehensive earnings	$95.9	$104.6	$110.9
The accompanying Notes are an integral part of these Consolidated Financial Statements. 240 _____________________________________________________________________________

POTOMAC ELECTRIC POWER COMPANY CONSOLIDATED BALANCE SHEETS
	December 31, 2004		December 31, 2003
ASSETS
(Millions of Dollars)
CURRENT ASSETS
Cash and cash equivalents		$    1.5	$    6.8
Accounts receivable, less allowance for uncollectible      accounts of $20.1 million and $18.4 million		307.9	269.5
Materials and supplies - at average cost		38.2	44.9
Prepaid expenses and other		6.8	26.0
Total Current Assets		354.4	347.2
INVESTMENTS AND OTHER ASSETS
Regulatory assets		125.7	121.2
Prepaid pension expense		171.1	168.1
Other		121.0	108.6
Total Investments and Other Assets		417.8	397.9
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		4,869.4	4,694.5
Accumulated depreciation		(1,937.8)	(1,769.6)
Net Property, Plant and Equipment		2,931.6	2,924.9
TOTAL ASSETS		$3,703.8	$3,670.0
The accompanying Notes are an integral part of these Consolidated Financial Statements. 241 ___________________________________________________________________________

POTOMAC ELECTRIC POWER COMPANY CONSOLIDATED BALANCE SHEETS
	December 31, 2004	December 31, 2003
LIABILITIES AND SHAREHOLDER'S EQUITY
(Millions of Dollars, except share data)
CURRENT LIABILITIES
Short-term debt	$  114.0	$  107.5
Accounts payable and accrued liabilities	124.3	135.4
Accounts payable to associated companies	25.5	24.2
Capital lease obligations due within one year	4.7	4.2
Taxes accrued	50.9	24.2
Interest accrued	22.0	19.3
Other	74.7	103.8
Total Current Liabilities	416.1	418.6
DEFERRED CREDITS
Regulatory liabilities	126.7	153.0
Income taxes	711.9	644.9
Investment tax credits	18.6	20.6
Other post-retirement benefit obligations	43.8	44.4
Other	37.4	39.9
Total Deferred Credits	938.4	902.8
LONG-TERM LIABILITIES
Long-term debt	1,198.3	1,130.4
Mandatorily redeemable serial preferred stock	-	45.0
Capital lease obligations	121.3	126.1
Total Long-Term Liabilities	1,319.6	1,301.5
COMMITMENTS AND CONTINGENCIES (NOTE 11)
REDEEMABLE SERIAL PREFERRED STOCK	27.0	35.3
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	507.6
Capital stock expense	(0.5)	(1.1)
Accumulated other comprehensive loss	(0.7)	-
Retained income	496.4	505.3
Total Shareholder's Equity	1,002.7	1,011.8
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$3,703.8	$3,670.0
The accompanying Notes are an integral part of these Consolidated Financial Statements. 242 __________________________________________________________________________

POTOMAC ELECTRIC POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Year Ended December 31,	2004		2003	2002
(Millions of Dollars)
OPERATING ACTIVITIES
Net Income	$   96.6		$  104.6	$  139.1
Adjustments to reconcile net income to net cash   from operating activities:
Depreciation and amortization	166.3		169.8	153.3
Rents received from leveraged leases       under income earned	-		-	(25.2)
Gain on sale of assets	(6.9)		-	(1.3)
Deferred income taxes	25.9		46.5	49.2
Investment tax credit adjustments, net	(2.0)		(2.0)	(2.0)
Changes in:
Accounts receivable	(38.5)		(6.7)	(21.6)
Proceeds received on accounts receivable         due from affiliate	-		31.2	-
Proceeds received on note receivable from affiliate	-		110.4	-
Regulatory assets and liabilities	(35.2)		(53.5)	105.4
Prepaid expenses	20.3		(15.7)	14.0
Accounts payable and accrued liabilities	(3.3)		(15.7)	17.6
Interest and taxes accrued, including         Federal income tax refund of         $135.4 million in 2002	49.3		(14.1)	26.4
Prepaid pension costs	(2.9)		(14.6)	(1.0)
Other post-retirement benefit obligation	(0.5)		5.3	11.0
Materials and supplies	6.7		(7.1)	0.1
Deferred charges and other	(3.7)		(7.2)	5.0
Deferred credits and other	2.4		(5.3)	1.8
Net Cash From Operating Activities	274.5		325.9	471.8
INVESTING ACTIVITIES
Net investment in property, plant and equipment	(204.1)		(197.5)	(194.7)
Proceeds from/changes in:
Purchase of leveraged leases	-		-	(111.6)
Sales of marketable securities	-		-	2.2
Purchases of other investments	-		-	(15.4)
Proceeds from sale of other investments	22.4		-	-
Sale of aircraft	-		-	4.1
Net other investing activities	-		-	(8.9)
Net Cash Used By Investing Activities	(181.7)		(197.5)	(324.3)
FINANCING ACTIVITIES
Dividend to Pepco Holdings	(102.4)		(64.9)	(432.3)
Dividends paid on Pepco preferred and common stock	(1.0)		(3.3)	(67.6)
Redemption of preferred stock	(53.3)		(2.5)	(2.0)
Reacquisition of Pepco's common stock	-		-	(2.2)
Redemption of trust preferred stock	-		(125.0)	-
Issuances of long-term debt	375.0		199.3	34.3
Reacquisitions of long-term debt	(210.0)		(205.0)	(129.6)
Repayments of short-term debt, net	(93.5)		67.5	(43.2)
Net other financing activities	(12.9)		(5.9)	(2.2)
Net Cash Used By Financing Activities	(98.1)		(139.8)	(644.8)
Net Decrease In Cash and Cash Equivalents	(5.3)		(11.4)	(497.3)
Cash and Cash Equivalents at Beginning of Year	6.8		18.2	515.5
CASH AND CASH EQUIVALENTS AT END OF YEAR	$    1.5	$	$    6.8	$   18.2
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest and paid (received)     for income taxes:
Interest	$   76.5		$   82.8	$  125.4
Income taxes	$    6.2		$   44.1	$ (144.1)
The accompanying Notes are an integral part of these Consolidated Financial Statements. 243 _____________________________________________________________________________

POTOMAC ELECTRIC POWER COMPANY CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
	Common Stock Shares    Par Value		Premium on Stock	Capital Stock Expense	Accumulated Other Comprehensive Income (Loss)	Retained Income
(Dollar Amounts in Millions)
BALANCE, DECEMBER 31, 2001	118,544,883	$118.5	$1,028.3	$(12.9)	($6.7)	$974. 1
Net Income	-	-	-	-	-	139.1
Other comprehensive income	-	-	-	-	4.2	-
Dividends:
Preferred stock	-	-	-	-	-	(5.0)
Common stock	-	-	-	-	-	(62.6)
Dividends to Pepco Holdings	-	-	-	-	-	(432.2)
Merger Related Transactions:
Transfer of ownership of PCI     and Pepco Energy Services	-	-	(545.9)	-	2.5	54.2
Change in shares outstanding     and par value of shares     due to cancellation	(107,221,076)	(107.2)	118.5	10.7	-	-
Premium on capital stock     retired, net of expense	-	-	(28.9)	-	-	18.2
Transfer of premium on     treasury shares	-	-	(62.1)	-	-	62.1
Cancellation of treasury     shares and related     capital stock expense	(11,323,707)	(11.3)	(2.3)	1.1	-	(279.0)
BALANCE, DECEMBER 31, 2002	100	$     -	$  507.6	$ (1.1)	$   -	$468.9
Net Income	-	-	-	-	-	104.6
Dividends:
Preferred stock	-	-	-	-	-	(3.3)
To Pepco Holdings	-	-	-	-	-	(64.9)
BALANCE, DECEMBER 31, 2003	100	$     -	$  507.6	$ (1.1)	$    -	$505.3
Net Income	-	-	-	-	-	96.6
Other comprehensive (loss)	-	-	-	-	(0.7)	-
Dividends:
Preferred stock	-	-	-	-	-	(1.0)
Dividends to Pepco Holdings	-	-	-	-	-	(102.4)
Of Investment to Pepco Holdings	-	-	-	-	-	(2.1)
Preferred stock repurchase	-	-	(0.1)	0.2	-	-
Preferred stock redemption	-	-	-	0.4	-	-
BALANCE, DECEMBER 31, 2004	100	$     -	$  507.5	$ (0.5)	$ (0.7)	$496.4
The accompanying Notes are an integral part of these Consolidated Financial Statements. 244 _____________________________________________________________________________

NOTES TO CONSOLIDATED 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. Pepco's service territory covers approximately 640 square miles and has a population of approximately 2 million. On August 1, 2002 Pepco completed its acquisition of Conectiv, at which time Pepco and Conectiv became wholly owned subsidiaries of Pepco Holdings, Inc. (Pepco Holdings or PHI). 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.

(2)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation Policy

     The accompanying consolidated financial statements include the accounts of Pepco and its wholly owned subsidiaries. All intercompany balances and transactions between subsidiaries have been eliminated. Pepco uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies where it holds a 20% to 50% voting interest and cannot exercise control over the operations and policies of the investment. Under the equity method, Pepco records its interest in the entity as an investment in the accompanying Consolidated Balance Sheets, and its percentage share of the entity's earnings are recorded in the accompanying Consolidated Statements of Income.

     Financial Accounting Standards Board (FASB) Interpretation No. 46 "Consolidation of Variable Interest Entities" (FIN 46) and FASB Interpretation No. 46-R "Consolidation of Variable Interest Entities" (FIN 46R) did not impact Pepco at December 31, 2003.

Composition of Consolidated Financial Statements

     The accompanying consolidated statements of earnings, consolidated statements of comprehensive earnings, and consolidated statements of cash flows for the years ended December 31, 2004 and 2003 include only Pepco's operations for the entire year. These statements for the year ended December 31, 2002 include Pepco's operations for the entire year, consolidated with its pre-merger subsidiaries through July 31, 2002. Accordingly, the statements referred to above for the years ended December 31, 2004 and 2003 are not comparable with those for the year ended December 31, 2002. However, the amounts included in the accompanying balance sheets and statements of shareholder's equity for the years ended December 31, 2004 and 2003, are comparable since both years reflect the accounting impact of the merger transaction.

Use of Estimates

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America, such as Statement of Position 94-6 "Disclosure of Certain Significant Risks and Uncertainties," requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and

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expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Examples of significant estimates used by Pepco include the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, pension assumptions, and judgment involved with assessing the probability of recovery of regulatory assets. Although Pepco believes that its estimates and assumptions are reasonable, they are based upon information presently available. Actual results may differ significantly from these estimates.

Regulation of Power Delivery Operations

     Pepco is regulated by the Maryland Public Service Commission (MPSC) and the District of Columbia Public Service Commission (DCPSC), and its wholesale business is regulated by the Federal Energy Regulatory Commission (FERC).

     Based on the regulatory framework in which it has operated, Pepco has historically applied, and in connection with its transmission and distribution business continues to apply, the provisions of Statement of Financial Accounting Standards No. 71 (SFAS No. 71) "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 allows regulated entities, in appropriate circumstances, to establish regulatory assets and to defer the income statement impact of certain costs that are expected to be recovered in future rates. Management's assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders, and other factors. Should existing facts or circumstances change in the future to indicate that a regulatory asset is not probable of recovery, then the regulatory asset would be charged to earnings.

     The components of Pepco's regulatory asset balances at December 31, 2004 and 2003, are as follows:

	2004	2003
	(Millions of Dollars)
Deferred recoverable income taxes	$ 65.4	$ 84.1
Deferred debt extinguishment costs	42.9	36.2
Other	17.4	0.9
Total regulatory assets	$125.7	$121.2

     The components of Pepco's regulatory liability balances at December 31, 2004 and 2003, are as follows:

	2004	2003
	(Millions of Dollars)
Deferred income taxes due to customers	$32.0	$ 35.6
Generation Procurement Credit, customer sharing   commitment, and other	17.5	41.0
Removal costs	77.2	76.4
Total regulatory liabilities	$126.7	$153.0

     A description of the regulatory assets and regulatory liabilities is as follows:

     Deferred Recoverable Income Taxes:Represents deferred income tax assets recognized from the normalization of flow-through items as a result of amounts previously provided to customers. As temporary differences between

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the financial statement and tax basis of assets reverse, deferred recoverable income taxes are amortized. There is no return on these deferrals.

     Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period. A return is received on these deferrals.

     Other:  Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years and generally do not receive a return.

     Deferred Income Taxes Due to Customers: Represents the portion of deferred income tax liabilities applicable to Pepco's utility operations that has not been reflected in current customer rates for which future payment to customers is probable. As temporary differences between the financial statement and tax basis of assets reverse, deferred recoverable income taxes are amortized.

     General Procurement Credit (GPC), Customer Sharing Commitment and Other: GPC represents the customers' share of profits that Pepco has realized on the procurement and resale of generation services to standard offer service customers that has not yet been distributed to customers. Pepco is currently distributing the customers' share of profits monthly to customers in a billing credit. Pepco's generation divestiture settlement agreements, approved by both the DCPSC and MPSC, required the sharing between customers and shareholders of any profits earned during the four year transition period in each jurisdiction.

     Removal Costs: Represents Pepco's asset retirement obligation associated with removal costs accrued using Commission approved depreciation rates for transmission, distribution, and general utility property. In accordance with SFAS No. 143, accruals for removal costs were classified as a regulatory liability.

Revenue Recognition

     Pepco's revenue for services rendered but unbilled as of the end of each month is accrued and included in the accounts receivable balance on the accompanying consolidated balance sheets. Pepco recorded amounts for unbilled revenue of $103.2 million and $74.5 million as of December 31, 2004 and 2003, respectively. These amounts are included in the "accounts receivable" line item in the accompanying consolidated balance sheets. Additionally, the collection of taxes related to the consumption of electricity by its customers, such as fuel, energy, or other similar taxes are components of the Company's tariffs and as such, are billed to customers and recorded in Operating Revenues. Payments of these taxes by the Company are recorded in Other Taxes. Excise tax related generally to the consumption of gasoline by the Company in the normal course of business is charged to operations, maintenance or construction, and is de minimis.

     In connection with Pepco's acquisition of Conectiv on August 1, 2002, ownership of Pepco's pre-merger subsidiaries, Potomac Capital Investment Corporation (PCI) and Pepco Energy Services, Inc. (Pepco Energy Services) was transferred to Pepco Holdings. Pre-merger revenue in 2002 recorded by Pepco from Pepco Energy Services' energy services contracts and from PCI's utility industry services contracts was recognized using the percentage-of-completion method of revenue recognition, which recognized revenue as work progressed on the contract. Revenue from Pepco Energy Services' electric

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and gas marketing businesses was recognized as services when rendered. Pepco Energy Services' and PCI's revenues were recorded by Pepco pre-merger.

Transition Power Agreement and Generation Procurement Credit

     As part of the agreement to divest its generation assets, Pepco entered into separate Transition Power Agreements (TPAs) with Mirant for the District of Columbia and Maryland. In connection with Mirant's bankruptcy proceeding, the TPAs were amended by the Amended Settlement Agreement and Release dated as of October 24, 2003 (Settlement Agreement). For information regarding the impact of Mirant's bankruptcy on Pepco's operations, refer to the Note (11) "Commitments and Contingencies, Relationship with Mirant Corporation" section, herein.

Asset Retirement Obligations

     Pepco adopted Financial Accounting Standards Board (FASB) Statement No. 143 entitled "Accounting for Asset Retirement Obligations" (SFAS No. 143), on January 1, 2003. This Statement establishes the accounting and reporting standards for measuring and recording asset retirement obligations. Based on the implementation of SFAS No. 143, at December 31, 2004 and 2003, $77.2 million and $76.4 million, respectively, of removal costs have been classified as a regulatory liability in the accompanying Consolidated Balance Sheets.

Cash and Cash Equivalents

     Cash and cash equivalents include cash on hand, money market funds, and commercial paper with original maturities of three months or less. Additionally, deposits in PHI's "money pool," which PHI and certain of its subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Accounts Receivable and Allowance for Uncollectible Accounts

     Pepco's accounts receivable balances primarily consist of customer account receivable, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date, usually within one month. Pepco uses the allowance method to account for uncollectible accounts receivable.

Capitalizable Interest and Allowance for Funds Used During Construction

     In accordance with the provisions of SFAS No. 34, "Capitalization of Interest Cost," the cost of financing the construction of Pepco Holdings' subsidiaries electric generating plants is capitalized. Other non-utility construction projects also include financing costs in accordance with SFAS No. 34. The cost of additions to, and replacements or betterments of, retirement units of property and plant is capitalized. Such costs include material, labor, the capitalization of an Allowance for Funds Used During Construction (AFUDC) and applicable indirect costs, including engineering, supervision, payroll taxes and employee benefits.

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     Pepco recorded AFUDC for borrowed funds of $1.2 million, $1.8 million, and $2.7 million for the years ended December 31, 2004, 2003, and 2002, respectively. These amounts are recorded as a reduction of "interest expense" within the "other income (expense)" caption in the accompanying consolidated statements of earnings.

     Pepco recorded amounts for AFUDC equity income of $2.0 million, $2.9 million, and $2.5 million for the years ended December 31, 2004, 2003, and 2002, respectively. The amounts are included in the "other income" caption of the accompanying consolidated statements of earnings.

Amortization Of Debt Issuance And Reacquisition Costs

     Expenses incurred in connection with the issuance of long-term debt, including premiums and discounts associated with such debt, are deferred and amortized over the lives of the respective debt issues. Costs associated with the reacquisition of debt are also deferred and amortized over the lives of the new issues.

Severance Costs

     In November 2004, PHI announced that its Power Delivery business planned to reduce its 4,200 employee work force by approximately 2% to 3% by the end of 2004. This work force reduction was accomplished through a combination of retirements and targeted reductions. This plan met the criteria for the accounting treatment provided under SFAS No. 88 "Employer's Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits" and SFAS No. 146 "Accounting for Costs Association with Exit or Disposal Activities," as applicable. Additionally, during 2002, Pepco Holdings' management approved initiatives by Pepco and Conectiv to streamline its operating structure by reducing the number of employees at each company. These initiatives met the criteria for the accounting treatment provided under EITF No. 94-3 "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Ex it an Activity (including Certain Costs Incurred in a Restructuring)." A roll forward of the severance accrual balance is as follows. (Amounts in millions)

Balance, December 31, 2002	$ 11.9
Accrued during 2003	-
Payments during 2003	(8.6)
Balance, December 31, 2003	3.3
Accrued during 2004	3.7
Payments/reversals during 2004	(2.7)
Balance, December 31, 2004	$  4.3

     Based on the number of employees that have accepted or are expected to accept the severance packages, substantially all of the severance liability related to the 2002 plan will be paid through mid 2005. Employees have the option of taking severance payments in a lump sum or over a period of time.

Pension and Other Post Retirement Benefit Plans

     Pepco Holdings sponsors a retirement plan that covers substantially all employees of Pepco, Conectiv and certain employees of other Pepco Holdings' subsidiaries (Retirement Plan). Following the consummation of the acquisition of Conectiv by Pepco on August 1, 2002, the Pepco General Retirement Plan and the Conectiv Retirement Plan were merged into the Retirement Plan on December 31, 2002. The provisions and benefits of the merged Retirement Plan for Pepco employees are identical to those of the original Pepco plan and for Conectiv employees the provisions and benefits of

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the merged Retirement Plan are identical to the original Conectiv plan. Pepco Holdings also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans. In addition to sponsoring non-contributory retirement plans, Pepco Holdings provides certain post-retirement health care and life insurance benefits for eligible retired employees.

     The Company accounts for the Retirement Plan in accordance with SFAS No. 87, "Employers' Accounting for Pensions" and its other post-retirement benefits in accordance with SFAS No. 106, "Employers' Accounting for Post-retirement Benefits Other Than Pensions." PHI's financial statement disclosures were prepared in accordance with SFAS No. 132, "Employers' Disclosures about Pensions and Other Post-retirement Benefits."

Long-Lived Asset Impairment Evaluation

     Pepco is required to evaluate certain assets that have long lives (for example, generating property and equipment and real estate) to determine if they are impaired when certain conditions exist. SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets," provides the accounting for impairments of long-lived assets and indicates that companies are required to test long-lived assets for recoverability whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or if there is a significant adverse change in the manner an asset is being used or its physical condition. For long-lived assets that are expected to be held and used, SFAS No. 144 requires that an impairment loss shall only be recognized if the carrying amount of an asset is not recoverable and exceeds its fair value .

Property Plant and Equipment

     Property, plant and equipment are recorded at cost. The carrying value of property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable under the provisions of SFAS No. 144. Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation. For additional information regarding the treatment of removal obligations, refer to the "Asset Retirement Obligations" section included in this Note to the consolidated financial statements.

     The annual provision for depreciation on electric and gas property, plant and equipment is computed on the straight-line basis using composite rates by classes of depreciable property. Accumulated depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. The relationship of the annual provision for depreciation for financial accounting purposes to average depreciable property was 3.5% for 2004, 2003, and 2002. Property, plant and equipment other than electric and gas facilities is generally depreciated on a straight-line basis over the useful lives of the assets.

Income Taxes

     Pepco, as a direct subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to Pepco based upon the taxable income or loss, determined on a separate return basis.

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     The Consolidated Financial Statements include current and deferred income taxes. Current income taxes represent the amounts of tax expected to be reported on Pepco's state income tax returns and the amount of federal income tax allocated from Pepco Holdings. Deferred income taxes are discussed below.

     Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement and tax basis of existing assets and liabilities and are measured using presently enacted tax rates. The portion of Pepco's deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in "regulatory assets" on the Consolidated Balance Sheets. For additional information, see the discussion under "Regulation of Power Delivery Operations" shown above.

     Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

     Investment tax credits from utility plants purchased in prior years are reported on the Consolidated Balance Sheets as "Investment tax credits." These investment tax credits are being amortized to income over the useful lives of the related utility plant.

SFAS No. 150

     Effective July 1, 2003 Pepco implemented SFAS No. 150 entitled "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS No. 150). This Statement established standards for how an issuer classifies and measures in its Consolidated Balance Sheet certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 resulted in Pepco's reclassification (initially as of September 30, 2003) of its "Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Which Holds Solely Parent Junior Subordinated Debentures" (TOPrS) and "Mandatorily Redeemable Serial Preferred Stock" on its Consolidated Balance Sheet to a long-term liability classification. Additionally, in accordance with the provisions of SFAS No. 150, dividends on the TOPrS and Mandatorily Redeemable Serial Preferred Stock, declared subsequent to the July 1, 2003 implementation of SFAS No. 150, are recorded as interest expense in Pepco's Consolidated Statement of Earnings for the years ended December 31, 2004 and 2003. In accordance with the transition provisions of SFAS No. 150, amounts prior to 2003 were not reclassified.

FIN 45

     Pepco applied the provisions of FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45), commencing in 2003 to its agreements that contain guarantee and indemnification clauses. These provisions expand those required by FASB Statement No. 5, "Accounting for Contingencies," by requiring a guarantor to recognize a liability on its balance sheet for the fair value of obligations it assumes under certain guarantees issued or modified after December 31, 2002 and to disclose certain types of guarantees, even if the likelihood of requiring the guarantor's performance under the guarantee is remote.

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     As of December 31, 2004 and 2003, Pepco did not have material obligations under guarantees or indemnifications issued or modified after December 31, 2002, that are required to be recognized as a liability on its balance sheets.

FIN 46

     On December 31, 2003, FIN 46 was implemented by Pepco. FIN 46 was revised and superseded by FASB Interpretation No. 46R (revised December 2003), "Consolidation of Variable Interest Entities" (FIN 46R) which clarified some of the provisions of FIN 46 and exempted certain entities from its requirements. FIN 46R was effective December 31, 2003 for variable interest entities that were considered to be special-purpose entities, and effective March 31, 2004 to all other variable interest entities. The implementation of FIN 46R (including the evaluation of interests in power purchase arrangements) did not impact Pepco's financial condition or results of operations for the years ended December 31, 2004 and 2003.

     As part of its FIN 46R evaluation, Pepco reviewed its power purchase agreements (PPAs), including its Non-Utility Generation (NUG) contracts, to determine (i) if its interest in each entity that is a counterparty to a PPA agreement was a variable interest, (ii) whether the entity was a variable interest entity and (iii) if so, whether Pepco was the primary beneficiary. Due to a variable element in the pricing structure of its PPA with one entity, Panda-Brandywine, L.P. (Panda), Pepco potentially assumes the variability in the operations of the plant of this entity and therefore has a variable interest in the entity. However, due to Pepco's inability to obtain information considered to be confidential and proprietary from the entity, Pepco 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 in the years ended December 31, 2004, 2003, and 2002 were approximately $76 million, $80 million, and $74 million, respectively. Pepco's exposure to loss under the Panda PPA is discussed in Note (11), Commitments and Contingencies, under "Relationship with Mirant Corporation."

Other Non-Current Assets

     The other assets balance principally consists of deferred compensation trust assets and unamortized debt expense.

Other Current Liabilities

     The other current liability balance principally consists of customer deposits, accrued vacation liability, and the current portion of deferred income taxes.

Other Deferred Credits

     The other deferred credits balance principally consists of miscellaneous deferred liabilities.

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Reclassifications

     Certain prior year amounts have been reclassified in order to conform to current year presentations.

(3)  SEGMENT INFORMATION

     As a result of the merger transaction on August 1, 2002, Pepco has determined that its utility operations represent its only operating segment under the provisions of Statement of Financial Accounting Standards No. 131 "Disclosures about Segments of an Enterprise and Related Information" (SFAS No. 131). The information presented is in millions of dollars.

	December 31, 2004
	Utility    Segment	PCI	Pepco EnergyServices	Elim.	Total   Pepco
Operating Revenue	$1,805.9	$   -	$   -	$   -	$1,805.9
Operating Expenses	1,579.7	-	-	-	1,579.7
Operating Income	226.2	-	-	-	226.2
Net Income	96.6	-	-	-	96.6
Total Assets	$3,703.8	$   -	$   -	$   -	$3,703.8

	December 31, 2003
	Utility    Segment	PCI	Pepco EnergyServices	Elim.	Total   Pepco
Operating Revenue	$1,548.0	$   -	$   -	$   -	$1,548.0
Operating Expenses	1,298.9	-	-	-	1,298.9
Operating Income	249.1	-	-	-	249.1
Net Income	104.6	-	-	-	104.6
Total Assets	$3,670.0	$   -	$   -	$   -	$3,670.0

	December 31, 2002
	Utility    Segment	PCI(B)	Pepco EnergyServices(B)	(A) Elim.	Total   Pepco
Operating Revenue	$1,533.9	$59.2	$401.0	$(6.1)	$1,988.0
Operating Expenses	1,241.5	26.3	401.4	(6.1)	1,663.1
Operating Income	292.4	32.9	(.4)	-	324.9
Net Income	124.0	14.9	.2	-	139.1
Total Assets	$3,770.4	$   -	$   -	$   -	$3,770.4

(A)	Represents the elimination of rent paid to PCI for Pepco's lease of office space in PCI's 10-story commercial office building. The lease commenced in June 2001.
(B)	Represents pre-merger operations through July 31, 2002.

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(4)  LEASING ACTIVITIES

     The investments in financing leases represented leases held by PCI and therefore were transferred by Pepco to Pepco Holdings on August 1, 2002, in accordance with the terms of the merger. The finance lease balance was comprised of the following:

     Income recognized from leveraged leases was comprised of the following:

	For the Year Ended       December 31,
	2004	2003	2002 (a)
	(Millions of Dollars)
Pre-tax earnings from leveraged leases	$   -	$   -	$31.8
Investment tax credit recognized	-	-	-
Income from leveraged leases, including      investment tax credit	-	-	31.8
Income tax expense	-	-	6.4
Net Income from Leveraged Leases	$   -	$   -	$25.4

(a) Due to the transfer of PCI on August 1, 2002, the 2002 amounts represent income from January 1, 2002 through July 31, 2002.

Lease Commitments

     Pepco leases its consolidated control center, an integrated energy management center used by Pepco's power dispatchers to centrally control the operation of its transmission and distribution systems. The lease is accounted for as a capital lease and was initially recorded at the present value of future lease payments, which totaled $152 million. The lease requires semi-annual payments of $7.6 million over a 25-year period and provides for transfer of ownership of the system to Pepco for $1 at the end of the lease term. Under SFAS No. 71, the amortization of leased assets is modified so that the total of interest on the obligation and amortization of the leased asset is equal to the rental expense allowed for rate-making purposes. This lease has been treated as an operating lease for rate-making purposes.

     Capital lease assets recorded within Property, Plant and Equipment at December 31, 2004 and 2003 are comprised of the following:

(Millions of Dollars)
At December 31, 2004	Original Cost	Accumulated Amortization	Net Book Value
Transmission	$ 76.0	$13.6	$ 62.4
Distribution	76.0	13.6	62.4
Other	2.6	1.2	1.4
Total	$154.6	$28.4	$126.2
At December 31, 2003
Transmission	$ 76.0	$11.6	$ 64.4
Distribution	76.0	11.6	64.4
Other	2.6	1.1	1.5
Total	$154.6	$24.3	$130.3

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(5)  PROPERTY, PLANT AND EQUIPMENT

     Property, plant and equipment is comprised of the following.

At December 31, 2004	Original   Cost	Accumulated Depreciation	Net    Book Value
	(Millions of Dollars)
Distribution	$3,501.3	$1,420.7	$2,080.6
Transmission	712.1	281.9	430.1
General	283.7	130.7	153.2
Construction work in progress	198.9	-	198.9
Non-operating and other property	173.4	104.5	68.8
Total	$4,869.4	$1,937.8	$2,931.6
At December 31, 2003
Distribution	$3,450.5	$1,301.5	$2,149.0
Transmission	701.0	255.5	445.5
General	387.1	155.0	232.1
Construction work in progress	51.6	-	51.6
Non-operating and other property	104.3	57.6	46.7
Total	$4,694.5	$1,769.6	$2,924.9

     The non-operating and other property amounts include balances for distribution and transmission plant held for future use as well as other property held by non-utility subsidiaries.

    Pepco uses separate depreciation rates for each electric plant account. The rates, which vary from jurisdiction to jurisdiction, were equivalent to a system-wide composite depreciation rate of approximately 3.5% for Pepco's transmission and distribution system property in 2004, 2003, and 2002.

(6)  PENSIONS AND OTHER POST-RETIREMENT BENEFITS

Pension Benefits

     Pepco Holdings sponsors a retirement plan that covers substantially all employees of Pepco, Conectiv and certain employees of other Pepco Holdings' subsidiaries (Retirement Plan). Following the consummation of the acquisition of Conectiv by Pepco on August 1, 2002, the Pepco General Retirement Plan and the Conectiv Retirement Plan were merged into the Retirement Plan on December 31, 2002. The provisions and benefits of the merged Retirement Plan for Pepco employees are identical to those of the original Pepco plan and for Conectiv employees the provisions and benefits are identical to those of the original Conectiv plan. Pepco Holdings also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans. Pepco Holdings uses a December 31 measurement date for its plans.

     The acquisition of Conectiv by Pepco in August 2002 resulted in purchase accounting requirements that are reflected in the net periodic pension cost. Under this accounting treatment, Conectiv's accrued pension liability was adjusted on August 1, 2002 through consolidation to recognize all previously unrecognized gains and losses arising from past experience different from that assumed, all unrecognized prior service costs, and the remainder of any unrecognized obligation or asset existing at the date of the initial application of SFAS No.87, "Employers' Accounting for Pensions." The Conectiv

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Retirement Plan transferred a projected benefit obligation of $804 million and plan assets of $744 million on August 1, 2002.

     Plan assets are stated at their market value as of the measurement date, December 31. All dollar amounts in the following tables are in millions of dollars.

     The following tables provide a roll forward of the changes in the projected benefit obligation and plan assets for the most recent two years.

	Pension Benefits
Change in Benefit Obligation	2004	2003
Benefit obligation at beginning of year	$1,579.2	$1,398.9
Service cost	35.9	33.0
Interest cost	94.7	93.7
Actuarial loss	51.4	144.4
Benefits paid	(113.2)	(90.8)
Benefit obligation at end of year	$1,648.0	$1,579.2
Change in Plan Assets
Fair value of plan assets at beginning of year	$1,462.8	$1,240.6
Actual return on plan assets	161.1	261.5
Company contributions	12.8	51.5
Benefits paid	(113.2)	(90.8)
Fair value of plan assets at end of year	$1,523.5	$1,462.8

     The following table provides a reconciliation of the projected benefit obligation, plan assets and funded status of the plans.

	Pension Benefits
	2004	2003
Fair value of plan assets at end of year	$1,523.5	$1,462.8
Benefit obligation at end of year	1,648.0	1,579.2
Funded status (plan assets less than plan obligations)	$(124.5)	$(116.4)
Amounts not recognized:
Unrecognized net actuarial loss	261.2	253.3
Unrecognized prior service cost	3.0	4.0
Net amount recognized	$ 139.7	$ 140.9

     The following table provides a reconciliation of the amounts recognized in PHI's Consolidated Balance Sheets as of December 31:

	Pension Benefits
	2004	2003
Prepaid benefit cost	$165.7	$166.6
Accrued benefit cost	(26.0)	(25.7)
Additional minimum liability for nonqualified plan	(7.0)	-
Intangible assets for nonqualified plan	.1	-
Accumulated other comprehensive income for   nonqualified plan	6.9	-
Net amount recognized	$139.7	$140.9

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     The accumulated benefit obligation for the Retirement Plan (the qualified defined benefit pension plan) was $1,462.9 million and $1,409.0 million at December 31, 2004, and 2003, respectively. The table below provides the projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the PHI nonqualified pension plan with an accumulated benefit obligation in excess of plan assets at December 31, 2004.

	Pension Benefits
	2004	2003
Projected benefit obligation for nonqualified plan	$35.3	$34.3
Accumulated benefit obligation for nonqualified plan	$32.9	$24.0
Fair value of plan assets for nonqualified plan	-	-

     In 2004, PHI was required to recognize an additional minimum liability and an intangible asset related to its nonqualified pension plan as prescribed by SFAS No. 87. The liability was recorded as a reduction to shareholders' equity (other comprehensive income), and the equity will be restored to the balance sheet in future periods when the accrued benefit liability exceeds the accumulated benefit obligation at future measurement dates. The amount of reduction to shareholders' equity (net of income taxes) in 2004 was $4.1 million. The recording of this reduction did not affect net income or cash flows in 2004 or compliance with debt covenants.

	Pension Benefits
Other additional information:	2004	2003
Decrease in other comprehensive income	$4.1	-

     The table below provides the components of net periodic benefit costs recognized for the years ended December 31. A portion of the net periodic benefit cost is capitalized within PHI's Consolidated Balance Sheets.

Components of Net Periodic Benefit Cost
	Pension Benefits
	2004	2003	2002
Service cost	$  35.9	$  33.0	$  16.0
Interest cost	94.7	93.7	54.1
Expected return on plan assets	(124.2)	(106.2)	(69.0)
Amortization of prior service cost	1.1	1.0	1.0
Amortization of net (gain) loss	6.5	13.9	6.9
Net periodic benefit cost	$  14.0	$  35.4	$  9.0

     The 2004 net periodic benefit cost of $14.0 million includes $7.5 million for Pepco. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries.

     The 2003 net periodic benefit cost of $35.4 million includes $15.7 million for Pepco. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries.

     The 2002 net periodic benefit cost amount of $9.0 million includes $6.1 million for Pepco. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries.

     The following weighted average assumptions were used to determine the benefit obligations at December 31:

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Assumptions
Weighted-average assumptions used to determine benefit obligations at December 31
	Pension Benefits
	2004	2003
Discount rate	5.875%	6.25%
Rate of compensation increase	4.50%	4.50%

     The following weighted average assumptions were used to determine the net periodic benefit cost for years ended December 31:

Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31
	Pension Benefits
	2004	2003
Discount rate	6.25%	6.75%
Expected long-term return on plan assets	8.75%	8.75%
Rate of compensation increase	4.50%	4.50%

     In selecting an expected rate of return on plan assets, PHI considers actual historical returns, economic forecasts and the judgment of its investment consultants on expected long-term performance for the types of investments held by the plan. The plan assets consist of equity and fixed income investments, and when viewed over a long time horizon, are expected to yield a return on assets of 8.75%.

Plan Assets

     Pepco Holdings' pension plan weighted-average asset allocations at December 31, 2004, and 2003, by asset category are as follows:

Asset Category	Plan Assets at December 31 2004      2003		Target Plan Asset Allocation	Minimum/ Maximum
Equity securities	66%	64%	60%	55% - 65%
Debt securities	33%	35%	35%	30% - 50%
Other	1%	1%	5%	0% - 10%
Total	100%	100%	100%

     In developing an asset allocation policy for its Retirement Plan, PHI examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, PHI examined the risk/return tradeoffs of alternative asset classes and asset mixes given long-term historical relationships, as well as prospective capital market returns. PHI also conducted an asset/liability study to match projected asset growth with projected liability growth and provide sufficient liquidity for projected benefit payments. By incorporating the results of these analyses with an assessment of its risk posture, and taking into account industry practices, PHI developed its asset mix guidelines. Under these guidelines, PHI diversifies assets in order to protect against large investment losses and to reduce the probability of excessive performance volatility while maximizing return at an acceptable risk level. Diversification of assets is impleme nted by allocating monies to various asset classes and investment styles within asset classes, and by retaining investment management firm(s) with complementary investment philosophies, styles and approaches. Based on the assessment of demographics,

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actuarial/funding, and business and financial characteristics, PHI believes that its risk posture is slightly below average relative to other pension plans. Consequently, Pepco Holdings believes that a slightly below average equity exposure (i.e., a target equity asset allocation of 60%) is appropriate for the Retirement Plan.

     On a periodic basis, Pepco Holdings reviews its asset mix and rebalances assets back to the target allocation over a reasonable period of time.

     No Pepco Holdings common stock is included in pension program assets.

Cash Flows

Contributions

     Pepco Holdings, Inc. funding policy with regard to the Retirement Plan is to maintain a funding level in excess of 100% with respect to its accumulated benefit obligation (ABO). PHI's Retirement Plan defined benefit plan currently meets the minimum funding requirements of ERISA without any additional funding. In 2004 and 2003, PHI made discretionary tax-deductible cash contributions to the plan of $10.0 million and $50.0 million, respectively, in line with its funding policy. Assuming no changes to the current pension plan assumptions, PHI projects no funding will be required under ERISA in 2005; however, PHI may elect to make a discretionary tax-deductible contribution, if required to maintain its plan assets in excess of its ABO.

Expected Benefit Payments

     The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid from the Retirement Plan:

Years	Pension       Benefits
2005	$ 89.4
2006	91.6
2007	102.0
2008	108.2
2009	113.4
2010-2014	619.7

Other Post-Retirement Benefits

     In addition to sponsoring non-contributory retirement plans, Pepco Holdings provides certain post-retirement health care and life insurance benefits for eligible retired employees. Certain groups of employees hired January 1, 2005 or later will not have company subsidized retiree medical coverage; however, they will be able to purchase coverage at full cost through the company. Pepco Holdings uses a December 31 measurement date for its plans.

     The acquisition of Conectiv by Pepco in August 2002 resulted in purchase accounting requirements that are reflected in the net periodic benefit cost. Under this accounting treatment, Conectiv's accrued post-retirement health care and life insurance liability was adjusted on August 1, 2002 through consolidation to recognize all previously unrecognized actuarial gains and losses, all unrecognized prior service costs, and the remainder of any unrecognized obligation or asset existing at the date of the initial application of SFAS No. 106. The Conectiv Plan transferred a projected benefit obligation of $320 million and plan assets of $100 million on August 1, 2002.

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     During 2004, PHI announced amendments to its post-retirement health care plans for certain groups of eligible employees. The amendments included changes to coverage and retiree cost-sharing, and are reflected as a reduction in PHI's 2004 net periodic benefit cost and a reduction of $42 million in projected benefit obligation at December 31, 2004.

     Plan assets are stated at their market value as of the measurement date, December 31. All dollar amounts in the following tables are in millions of dollars.

     The following tables provide a roll forward of the changes in the benefit obligation and plan assets for the most recent two years: 

	Other Post- Retirement Benefits
	2004	2003
Change in Benefit Obligation
Benefit obligation at beginning of year	$ 511.9	$ 472.4
Service cost	8.6	9.4
Interest cost	35.4	32.9
Amendments	(42.4)	-
Actuarial loss	117.0	31.0
Benefits paid	(37.0)	(33.8)
Benefit obligation at end of year	$ 593.5	$ 511.9
Change in Plan Assets
Fair value of plan assets at beginning of year	$ 145.2	$ 123.0
Actual return on plan assets	15.7	25.8
Company contributions	41.0	30.2
Benefits paid	(37.0)	(33.8)
Fair value of plan assets at end of year	$ 164.9	$ 145.2

     The following table provides a reconciliation of benefit obligations, plan assets and funded status of the plans:

	Other Post- Retirement Benefits
	2004	2003
Fair value of plan assets at end of year	$164.9	$145.2
Benefit obligation at end of year	593.5	511.9
Funded status (plan assets less than plan obligations)	(428.6)	(366.7)
Amounts not recognized:
Unrecognized net actuarial loss	188.5	89.0
Unrecognized initial net obligation	(29.5)	10.8
Net amount recognized	$(269.6)	$(266.9)

     The following table provides a reconciliation of the amounts recognized in PHI's Consolidated Balance Sheets as of December 31:

	Other Post- Retirement Benefits
	2004	2003
Prepaid benefit cost	$     -	$     -
Accrued benefit cost	(269.6)	(266.9)
Net amount recognized	$(269.6)	$(266.9)

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     The table below provides the components of net periodic benefit costs recognized for the years ended December 31. A portion of the net periodic benefit cost is capitalized within PHI's Consolidated Balance Sheets.

Components of Net Periodic Benefit Cost
	Other Post- Retirement Benefits
	2004	2003	2002
Service cost	$ 8.6	$ 9.5	$ 7.2
Interest cost	35.4	32.9	20.0
Expected return on plan assets	(9.9)	(8.3)	(5.2)
Recognized actuarial loss	9.5	8.0	6.1
Net periodic benefit cost	$43.6	$42.1	$28.1

     The 2004 net periodic benefit cost amount of $43.6 million, includes $16.7 million for Pepco. The remaining net periodic benefit cost is related to other PHI subsidiaries. The 2003 net periodic benefit cost amount of $42.1 million, includes $18.0 million for Pepco. The remaining net periodic benefit cost is related to other PHI subsidiaries. The 2002 net periodic benefit cost amount of $28.1 million includes $18.4 million for Pepco. The remaining 2002 net periodic benefit cost is related to other PHI subsidiaries.

     The following weighted average assumptions were used to determine the benefit obligations at December 31:

Assumptions
Weighted-average assumptions used to determine benefit obligations at December 31
	Other Post- Retirement Benefits
	2004	2003
Discount rate	5.875%	6.25%
Rate of compensation increase	4.50%	4.50%

     The following weighted average assumptions were used to determine the net periodic benefit cost for years ended December 31:

Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31
	Other Post- Retirement Benefits
	2004	2003
Discount rate	6.25%	6.75%
Expected long-term return on plan assets	8.75%	8.75%
Rate of compensation increase	4.50%	4.50%

     In selecting an expected rate of return on plan assets, PHI considers actual historical returns, economic forecasts and the judgment of its investment consultants on expected long-term performance for the types of investments held by the plan. The plan assets consist of equity and fixed income investments, and when viewed over a long time horizon, are expected to yield a return on assets of 8.75%.

     The table below provides the assumed health care trend rates as of December 31:

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Assumed health care cost trend rates at December 31
	2004	2003
Health care cost trend rate assumed for next year	9%	8%
Rate to which the cost trend rate is assumed to   decline (the ultimate trend rate)	5%	5%
Year that the rate reaches the ultimate trend rate	2009	2007

     Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1-Percentage- Point Increase	1-Percentage- Point Decrease
Effect on total of service and interest cost	$ 1.8	$ (1.7)
Effect on post-retirement benefit obligation	25.0	(23.0)

Plan Assets

     Pepco Holdings' post-retirement plan weighted-average asset allocations at December 31, 2004, and 2003, by asset category are as follows:

	Plan Assets    at December 31,    2004         2003
Asset Category
Equity securities	65%	63%
Debt securities	35%	37%
Total	100%	100%

     No Pepco Holdings common stock is included in post-retirement program assets.

Cash Flows

Contributions

     Pepco funded the 2004 and 2003 portions of its estimated liability for Pepco post-retirement medical and life insurance costs through the use of an Internal Revenue Code (IRC) 401 (h) account, within Pepco Holdings' Retirement Plan, and an IRC 501 (C) (9) Voluntary Employee Beneficiary Association (VEBA). In 2004 and 2003, Pepco contributed $4.7 million to the plans and assuming no changes to the current pension plan assumptions, expects similar amounts to be contributed in 2005.

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Expected Benefit Payments

     The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Years	Pension       Benefits
2005	$ 36.0
2006	36.3
2007	38.6
2008	40.6
2009	42.4
2010-2014	225.3

     FASB Staff Position (FSP 106-2), Accounting and Disclosure
       Requirements Related to the Medicare Prescription Drug, Improvement
       and Modernization Act of 2003

     The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) became effective on December 8, 2003. The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

     Pepco Holdings sponsors post-retirement health care plans that provide prescription drug benefits. Pepco Holdings did not elect the deferral of appropriate accounting permitted by the FASB Staff position (FSP) 106-1. The Accumulated Post-retirement Benefit Obligation (APBO) as of December 31, 2004 and December 31, 2003 has been reduced by $28 million to reflect the effects of the Act. This reduction includes both the decrease in the cost of future benefits being earned and an amortization of the APBO reduction over the future average working lifetime of the participants, or 12 years.The anticipated claims costs expected to be incurred have been adjusted to reflect the cost sharing between Medicare and Pepco Holdings. Participation rates have not been changed. In reflecting the effects of the Act, Pepco Holdings has determined which plans are eligible for Medicare cost sharing by analyzing the terms of each of its plans. It has rec ognized Medicare cost sharing for a plan only if Pepco Holdings' projected prescription drug coverage is expected to be at least as generous as the expected contribution by Medicare to a prescription drug plan not provided by Pepco Holdings.

     The effect of the subsidy on the 2004 other post-retirement net periodic benefit cost of $43.6 million is approximately a $3.6 million reduction due to the subsidy. Approximately $2.0 million is related to the amortization of the actuarial gain, and approximately $1.6 million is a subsidy-related reduction in interest cost on the APBO.

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(7)  LONG-TERM DEBT

     The components of long-term debt are shown below.

			At December 31,
Interest Rate	Maturity		2004		2003
			(Millions of Dollars)
First Mortgage Bonds
6.50%	2005		100.0		100.0
6.25%	2007		175.0		175.0
6.50%	2008		78.0		78.0
5.875%	2008		50.0		50.0
5.75% (a)	2010		16.0		16.0
4.95% (a)	2013		200.0		200.0
4.65% (a)	2014		175.0		-
6.00% (a)	2022		30.0		30.0
6.375% (a)	2023		37.0		37.0
6.875%	2023		-		100.0
5.375% (a)	2024		42.5		42.5
5.375% (a)	2024		38.3		38.3
6.875%	2024		-		75.0
7.375%	2025		75.0		75.0
5.75% (a)	2034		100.0		-
Total First Mortgage Bonds			1,116.8		1,016.8
Medium-Term Notes
7.64%	2007		35.0		35.0
6.25%	2009		50.0		50.0
7.00%	2024		-		35.0
Notes (Unsecured)
Variable	2006		100.0		-
Net unamortized discount			(3.5)		(6.4)
Current portion (b)			(100.0)		-
Net Long-Term Debt		$	1,198.3	$	1,130.4

(a)  First Mortgage Bonds issued as security for tax-exempt bonds and senior notes.

(b)  Included in short-term debt on the accompanying consolidated balance sheets.

     The outstanding First Mortgage Bonds are secured by a lien on substantially all of Pepco's property, plant and equipment.

     The aggregate principal amount of long-term debt outstanding at December 31, 2004, that will mature in each of 2005 through 2009 and thereafter is as follows: $100 million in 2005, $100 million in 2006, $210 million in 2007, $128 million in 2008, $50 million in 2009 and $713.8 million thereafter.

SHORT-TERM DEBT

     Pepco, a regulated utility, has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. A detail of the components of Pepco's short-term debt at December 31, 2004 and 2003 is as follows.

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	2004	2003
	(Millions of Dollars)
Commercial paper	$    -	$    -
Inter-Company borrowings	14.0	57.5
Floating rate note	-	50.0
Current portion of long-term debt	100.0	-
Total	$114.0	$107.5

Commercial Paper

     Pepco maintains an ongoing commercial paper program of up to $300 million. The commercial paper notes can be issued with maturities up to 270 days from the date of issue. The commercial paper program is backed by $500 million in credit facilities, shared with DPL and ACE. Pepco's credit limit under the facilities is the lower of $300 million and the maximum amount of short-term debt authorized by the applicable regulatory authority, except that the aggregate amount of credit utilized by Pepco, DPL and ACE at any given time under these facilities may not exceed $500 million.

     Pepco had no commercial paper outstanding at December 31, 2004 and December 31, 2003. The interest rate for commercial paper issued during 2004 was 1.07%. Interest rates for commercial paper issued during 2003 ranged from 1.00% to 1.43%. Maturities were less than 270 days for all commercial paper issued.

Floating Rate Note

     A $50 million floating rate bank note entered into by Pepco in 2003 matured in March 2004, on which the interest rate ranged from 1.60% to 1.61% during 2004 and 1.62% to 1.69% during 2003.

Credit Facility Agreements

     In July 2004, Pepco Holdings, Pepco, DPL and ACE entered into a five-year credit agreement with an aggregate borrowing limit of $650 million. This agreement replaced a $550 million 364-day credit agreement that was entered into on July 29, 2003. The respective companies also are parties to a three-year credit agreement that was entered into in July 2003 and terminates in July 2006 with an aggregate borrowing limit of $550 million. Pepco Holdings' credit limit under these facilities is $700 million, and the credit limit of each of Pepco, DPL and ACE under these facilities is the lower of $300 million and the maximum amount of short-term debt authorized by the appropriate state commission, except that the aggregate amount of credit utilized by Pepco, DPL and ACE at any given time under these facilities maynot exceed $500 million. Funds borrowed under these facilities are available for general corporate purposes. Either credit fac ility also can be used as credit support for the commercial paper programs of the respective companies. The three-year and five-year credit agreements contain customary financial and other covenants that, if not satisfied, could result in the acceleration of repayment obligations under the agreements or restrict the ability of the companies to borrow under the agreements. Among these covenants is 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 agreements. As of December 31, 2004, the applicable ratios for Pepco Holdings, Pepco, DPL and ACE were 59.0%, 58.5%, 52.1% and 50.2%, respectively. The credit agreements also contain a number

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of customary events of default that could result in the acceleration of repayment obligations under the agreements, including (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 agreements) of Pepco Holdings or the failure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE.

(8)  INCOME TAXES

     Pepco, as a direct subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to Pepco pursuant to a written tax sharing agreement which was approved by the SEC as part of Pepco's acquisition of Conectiv on August 1, 2002. Under this tax sharing agreement, PHI's consolidated federal income tax liability is allocated based upon PHI's and its subsidiaries' separate taxable income or loss, with the exception of the tax benefits applicable to non-acquisition debt expenses of PHI. Such tax benefits are allocated to subsidiaries with taxable income.

     The provision for income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred tax liabilities (assets) are shown below.

Provision for Income Taxes

	For the Year Ended December 31,
		2004			2003			2002
		(Millions of Dollars)
Current Tax Expense
Federal	$		20.2	$		10.7	$		(99.3)
State and local			12.6			14.0			(17.7)
Total Current Tax Expense (Benefit)			32.8			24.7			(117.0)
Deferred Tax Expense
Federal			27.5			45.4			163.8
State and local			(1.6)			1.0			35.5
Investment tax credits			(2.0)			(2.0)			(2.0)
Total Deferred Tax Expense			23.9			44.4			197.3
Total Income Tax Expense	$		56.7	$		69.1	$		80.3

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Reconciliation of Consolidated Income Tax Expense

		For the Year Ended December 31,
		2004			2003			2002
		(Millions of Dollars)
		Amount	Rate		Amount	Rate		Amount	Rate
Income Before Income Taxes	$	153.3		$	173.7		$	219.4
Income tax at federal statutory rate	$	53.7	.35	$	60.8	.35	$	76.8	.35
Increases (decreases) resulting from
Depreciation		5.9	.04		8.2	.05		6.9	.03
Removal costs		(1.7)	(.01)		(4.6)	(.03)		(2.4)	(.01)
State income taxes, net of       federal effect		7.2	.04		9.8	.06		11.2	.05
Tax credits		(2.7)	(.02)		(2.0)	(.01)		(2.4)	(.01)
Change in estimates related to       tax liabilities of prior years		(3.8)	(.02)		-	-		-	-
Other		(1.9)	(.01)		(3.1)	(.02)		(9.8)	(.04)
Total Income Tax Expense	$	56.7	. 37	$	69.1	.40	$	80.3	.37

Components of Consolidated Deferred Tax Liabilities (Assets)

		At December 31,
	2004		2003
	(Millions of Dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other book to tax basis differences	$	725.1	$	687.9
Pension plan contribution		72.5		79.4
Other Post Employment Benefits		(18.1)		(14.4)
Deferred taxes on amounts to be collected through     future rates		13.4		19.5
Deferred investment tax credit		(17.3)		(17.3)
Contributions in aid of construction		(56.9)		(54.6)
Customer sharing		(.4)		(.4)
Transition costs		(14.3)		(14.3)
Property taxes and other		7.4		15.3
Total Deferred Tax Liabilities, Net		711.4		701.1
Deferred tax liabilities included in   Other Current Liabilities		.5		(56.2)
Total Deferred Tax Liabilities, Net - Non-Current	$	711.9	$	644.9

     The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to Pepco's operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 2004 and 2003.

     The Tax Reform Act of 1986 repealed the Investment Tax Credit (ITC) for property placed in service after December 31, 1985, except for certain transition property. ITC previously earned on Pepco's property continues to be normalized over the remaining service lives of the related assets.

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     Pepco's federal income tax liabilities for all years through 2000 have been determined, subject to adjustment to the extent of any net operating loss or credit carrybacks from subsequent years. Pepco is of the opinion that the final settlement of its federal income tax liabilities for subsequent years will not have a material adverse effect on its financial condition or results of operations.

Taxes Other Than Income Taxes

     Taxes, other than income taxes, charged to operating expense for each period are shown below.

	2004	2003	2002
Gross Receipts/Delivery	$103.3	$ 99.7	$ 93.7
Property	37.0	36.7	42.1
County Fuel and Energy	70.6	36.7	17.9
Environmental, Use and Other	37.8	33.4	44.5
Total	$248.7	$206.5	$198.2

(9)  PREFERRED STOCK

     The preferred stock amounts outstanding as of December 31, 2004 and 2003 are as follows.

Series	Redemption    Price	Shares Outstanding 2004       2003		December 31,   2004        2003
				(Millions of Dollars)
Serial Preferred
$2.44 Series of 1957	$51.00	239,641	239,641	$12.0	$12.0
$2.46 Series of 1958	$51.00	173,892	173,892	8.7	8.7
$2.28 Series of 1965 (a)	$51.00	125,857	291,759	6.3	14.6
				$27.0	$35.3
Mandatorily Redeemable Serial Preferred
$3.40 Series of 1992(b)		-	900,000	-	$45.0

(a)

In September and October of 2004, Pepco redeemed 81,400 and 84,502 shares, respectively, of its $2.28 Series 1965 Serial Preferred Stock at an aggregate redemption price of $4.1 million and $4.2 million, respectively.

(b)

The shares of Pepco's $3.40 Serial Preferred Stock Series of 1992 were subject to mandatory redemption, at par, through the operation of a sinking fund that began redeeming 50,000 shares annually, on September 1, 2002, with all then outstanding shares to be redeemed by September 1, 2007. The shares were not redeemable prior to September 1, 2002; thereafter, the shares are redeemable at par. On September 2, 2003, Pepco redeemed $2.5 million or 50,000 shares of its $3.40 Serial Preferred Stock Series of 1992 pursuant to mandatory sinking fund provisions. In September 2004, Pepco redeemed $2.5 million or 50,000 shares of its $3.40 Serial Preferred Stock Series of 1992 pursuant to mandatory sinking fund provisions. In December 2004, Pepco repurchased all of the remaining 850,000 shares issued and outstanding at par or an aggregate of $42.5 million.

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(10)FAIR VALUE OF FINANCIAL INSTRUMENTS

     The estimated fair values of Pepco's financial instruments at December 31, 2004 and 2003 are shown below.

		At December 31,
		2004			2003
		(Millions of Dollars)
	Carrying  Amount		Fair Value	Carrying  Amount		Fair Value
Liabilities and Capitalization
Long-Term Debt		$1,198.3	$1,221.2		$1,130.4	$1,206.2
Serial Preferred Stock		$   27.0	$   21.7		$   35.3	$   26.9
Mandatorily Redeemable Serial Preferred Stock		$      -	$      -		$   45.0	$   45.1

     The methods and assumptions below were used to estimate, at December 31, 2004 and 2003, the fair value of each class of financial instrument shown above for which it is practicable to estimate that value.

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

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

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

(11) 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., pursuant to an Asset Purchase and Sale Agreement. As part of the Asset Purchase and Sale Agreement, Pepco entered into several ongoing contractual arrangements with Mirant 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).

     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 currently 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 have arisen or may arise due to the Mirant bankruptcy. Accordingly, management does not

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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 standard offer service obligations in Maryland through June 2004 and its standard offer service 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 that 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 current plan of reorganization filed by the Mirant entities with the Bankruptcy Court, certain Mirant entities other than Mirant Corporation would pay significantly higher portions 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 e ntities 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 an agreement with Panda, entered into in 1991, Pepco is obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (the Panda PPA). 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 Oblig ations).

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     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 which 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 this uncertainty, Pepco, in the third quarter of 2003, expen sed $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 amou nt ultimately recovered could be higher or lower.

     Mirant's Attempt to Reject the PPA-Related Obligations

     On August 28, 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). On August 4, 2004, the Court of Appeals remanded the case to the District Court saying that the District Court has jurisdiction to rule on the merits of Mirant's rejection motion, suggesting that in doing so the court apply a "more ri gorous standard" than the business judgment 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 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, 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.

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     As more fully discussed below, Mirant had been making regular periodic payments in respect of the PPA-Related Obligations. On December 9, 2004, Mirant filed a notice with the Bankruptcy Court that it was suspending payments to Pepco in respect of the PPA-Related Obligations. On December 13, 2004, Mirant failed to make a payment of approximately $17.9 million due to Pepco for the period November 1, 2004 to November 30, 2004. Mirant failed to make that payment. On December 23, 2004, Pepco received a payment of approximately $6.8 million from Mirant, which according to Mirant represented the market value of the power for which payment was due on December 13. Mirant has informed Pepco that it intends to continue to pay the market value, but not the above-market portion, of the power purchased under the PPA-Related Obligations. Pepco disagrees with Mirant's assertion that it need only pay the market value and believes that the amount repr esenting the market value calculated by Mirant is insufficient.

     On January 21, 2005, Mirant made a approximately $21.1 million, which, according to Mirant, includes the payment for the FirstEnergy PPA for December 2004 and "includes the December 2004 TPA revenue in the amount of $29,093,173.43, the TPA costs in the amount of $37,865,924.10, and an allocated share of [FirstEnergy's] PPA bill credits/charges in the amount of $5,490,164.79." Pepco disputes Mirant's contention that the amount paid reflects the full amount due Pepco under these agreements for the applicable periods.

     As of March 1, 2005, Mirant has withheld payment of approximately $34.8 million due to Pepco under 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. On March 1, 2005 (as amended by order dated March 7, 2005), the District Court granted Pepco's motion to withdraw jurisdiction over the Asset Purchase and Sale Agreement rejection proceedings from the Bankruptcy Court. In addition, the District Court ordered Mirant to pay on March 18, 2005, all past-due unpaid amounts under the PPA-Related Obligations. Mirant has filed a motion for reconsideration and a stay of the March 1, 2005 order.

     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 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 $133.2 million as of March 1, 2005 (assuming Mirant continues to withhold unpaid amounts of approximately $34.8 million as of March 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 March 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 March 1, 2005, at the rates provided in the PPA (with an average price per kilowatt hour of approximately 6.0 cents) and resold the capacity and energy at market rates projected, given the characteristics of the FirstEnergy PPA, to be approximately 5.0 cents per kilowatt hour, Pepco estimates that it would cost approximately $31 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 March 1, 2005, at the rates provided in the PPA (with an average price per kilowatt hour of approximately 16.9 cents), and resold the capacity and energy at market rates projected, given the characteristics of the Panda PPA, to be approximately 7.4 cents per kilowatt hour, Pepco estimates that it would cost approximately $29 million for the remainder of 2005, approximately $34 million in 2006 and 2007, and approximately $34 million to $49 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.

     If Mirant ultimately is successful in rejecting the PPA-Related Obligations and Pepco's full claim is not recovered from the Mirant

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bankruptcy estate, Pepco may seek authority from the MPSC and the 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 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 regulator y 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. However, the accounting treatment of such a loss depends on a number of legal and regulatory factors, and is not determinable at this time.

     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.

     On March 15, 2004, Mirant filed a complaint with the Bankruptcy Court seeking a declaratory judgment that the facility and capacity credit 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.

Rate Proceedings

     In compliance with the settlement approved by the MPSC in connection with the merger of Pepco and Conectiv, on December 4, 2003, Pepco submitted testimony and supporting schedules to review and reset if necessary its electricity distribution rates in Maryland to be effective July 1, 2004, when the then-current distribution rate freeze/caps ended. Pepco's filing demonstrated that it was in an under-earning situation. However the merger settlement provided that Pepco's distribution rates after July 1, 2004 could only remain the same or be decreased. With limited exceptions, Pepco cannot increase its distribution rates until January 1, 2007. In an order dated July 6, 2004 the MPSC affirmed the Hearing Examiner's recommendation that no rate decrease was warranted at that time.

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     On July 3, 2004, Pepco filed a distribution rate review case with the DCPSC as required by the terms of the Pepco-Conectiv merger settlement approved by the DCPSC. This case will determine whether Pepco's distribution rates will be decreased. In accordance with the terms of the merger settlement, Pepco's distribution rates cannot be increased as a result of the case. On November 24, 2004, the DCPSC issued an order that designated the issues to be considered in the case and set the hearing schedule. On December 17, 2004, Pepco filed supplemental direct testimony addressing the DCPSC-designated issues. Pepco's filings indicate that no rate decrease is warranted. On March 4, 2005, the DCPSC issued an order granting a joint motion filed on March 3, 2005, on behalf of Pepco and several other parties in the case to suspend the procedural schedule to allow the parties to focus on completing settlement discussions. In the joint motion, the movin g parties informed the DCPSC that they had agreed in principle to settlement provisions that would resolve all issues in the proceeding and that a settlement agreement could be filed in the near future.

Divestiture Cases

     District of Columbia

     Final briefs on Pepco's District of Columbia divestiture proceeds sharing application were filed on July 31, 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. 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. On March 4, 2003, the Internal Revenue Service (IRS) issued a notice of proposed rulemaking (NOPR) that is relevant to that principal issue. Comments on the NOPR were filed by several parties on June 2, 2003, and the IRS held a public hearing on June 25, 2003. 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 then 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 regulati ons. Other issues in the proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.

     Pepco believes that a sharing of EDIT and ADITC would violate the 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 ADITC balance, 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

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order is issued and all rights to appeal have been exhausted or lapsed, or the date the DCPSC order becomes operative. As of December 31, 2004, the District of Columbia jurisdictional transmission and distribution-related ADITC balance was approximately $6.0 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 D.C. 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. Reply briefs were filed in May 2002. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that was raised in the D.C. case. As of December 31, 2004, 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, 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 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 operative. As of December 31, 2004, the Maryland retail jurisdictional tran smission and distribution-related ADITC balance was approximately $10.7 million. The Hearing Examiner decided all other issues in favor of Pepco, except 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 4, 2003 IRS NOPR.

     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

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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 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.

SOS and Default Service Proceedings

     District of Columbia

     In February 2003, the DCPSC opened a new proceeding to consider issues relating to (a) the establishment of terms and conditions for providing standard offer service (SOS) in the District of Columbia after Pepco's obligation to provide SOS terminated on February 7, 2005, and (b) the selection of a new SOS provider.

     In December 2003, the DCPSC issued an order that set forth the terms and conditions for the selection of a new SOS provider(s) and the provision of SOS by Pepco on a contingency basis. In December 2003, the DCPSC also issued an order adopting terms and conditions that would apply if Pepco continued as the SOS provider after February 7, 2005. In March 2004, the DCPSC issued an order adopting the wholesale SOS model, i.e., Pepco would continue to be the SOS provider in the District of Columbia after February 7, 2005. This March 2004 order, as amended by a DCPSC order issued in July 2004, extends Pepco's obligation to provide default electricity supply at market rates for up to an additional 76 months for small commercial and residential customers, and for an additional 28 months for large commercial customers.

     In August 2004, the DCPSC issued an order adopting administrative charges for residential, small and large commercial DC SOS customers that are intended to allow Pepco to recover the administrative costs incurred to provide the SOS supply. The approved administrative charges include an average margin for Pepco of approximately $0.00248 per kilowatt hour, calculated based on total sales to residential, small and large commercial DC SOS customers over the twelve months ended December 31, 2003. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of DC SOS customers from each customer class and the load taken by such customers over the time period. The administrative charges went into effect for Pepco's DC SOS sales on February 8, 2005. Pepco completed the first competitive procurement process for DC SOS at the end of October and filed the proposed new SOS rates with the DC PSC on November 3, 2004.

     The TPA with Mirant under which Pepco obtained the fixed-rate DC 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 DC 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 DC SOS rates charged to customers during the period from January 23 through January 31, 2005. In addition, because the new DC SOS rates did not go into effect until February 8, 2005, Pepco had to pay the

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difference between the procurement cost of power under the new DC SOS contracts and the DC 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, will be included in the calculation of the Generation Procurement Credit (GPC) for DC 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 recovery from the Mirant bankruptcy estate associated with the TPA Settlement, the GPC would be re calculated, 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.

     Maryland

     Under a settlement approved by the MPSC in April 2003 addressing SOS service in Maryland following the expiration of Pepco's fixed-rate default supply obligations in July 2004, Pepco is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customers through May 2006, and to large commercial customers through May 2005. In accordance with the settlement, Pepco purchases the power supply required to satisfy its market rate default supply obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved by the MPSC. Pepco is entitled to recover from its default supply customers the cost of the default supply plus an average margin of $0.002 per kilowatt hour, calculated based on total sales to residential, small and large commercial Maryland SOS customers over the twelve months ended December 31, 200 3. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of Maryland SOS customers from each customer class and the load taken by such customers over the time period.

General Litigation

     Asbestos

     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, plaintiffs argue 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

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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

     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 August 2001, Pepco entered into a consent decree for de minimis parties with EPA to resolve its liability at this site. Under the terms of the consent decree, which was approved by the U.S. District Court for the District of Maryland on March 31, 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 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, 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 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. On May 12, 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. On October 2, 2003, the Bankruptcy Court confirmed a Reorganization Plan that incorporates

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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 December 31, 2004, Pepco had accrued $1.7 million to meet its liability for a site remedy. 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.

     On April 7, 2000, approximately 139,000 gallons of oil leaked from a pipeline at a generating facility that was owned by Pepco at Chalk Point generating facility in Aquasco, Maryland. The pipeline was operated by Support Terminals Services Operating Partnership LP (ST Services), an unaffiliated pipeline management company. The oil spread from Swanson Creek to the Patuxent River and several of its tributaries. The area affected covers portions of 17 miles of shoreline along the Patuxent River and approximately 45 acres of marshland adjacent to the Chalk Point property.

     In December 2000, the Department of Transportation, Office of Pipeline Safety, Research and Special Programs Administration (OPS) issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (NOPV). The NOPV alleged various deficiencies in compliance with regulations related to spill reporting, operations and maintenance of the pipeline and record keeping, none of which relate to the cause of the spill. The NOPV was issued to both Pepco and ST Services and proposed a civil penalty in the amount of $674,000. On June 2, 2004, the OPS issued a Final Order regarding the NOPV in this matter. The Final Order assessed a total fine of $330,250, with $256,250 of that amount assessed jointly against Pepco and ST Services and the remaining $74,000 assessed solely against ST Services. ST Services subsequently filed a Petition for Reconsideration. All penalties were stayed pending the outcome of the Petition for Rec onsideration. On February 9, 2005, OPS issued a Decision on the Petition for Reconsideration that affirmed the Final Order. Pepco's share of the $330,250 penalty assessed pursuant to the Final Order amounts to $128,125.

(12)  RELATED PARTY TRANSACTIONS

     PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including Pepco. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries' share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated in consolidation and no profit results from these transactions. PHI Service Company costs directly charged or allocated to Pepco for the years ended December 31, 2004, 2003 and 2002 were approximately $90.1 million, $82.8 million and $2.6 million, respectively. In 2002, Pepco charged $6.4 million to PHI Service Company for various administrative and professional services.

     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 years ended December 31, 2004, 2003 and 2002 were approximately $14.1 million, $11.3 million and $10.7 million, respectively.

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     In addition to the transactions described above, Pepco's financial statements include the following related party transactions in its Consolidated Statement of Earnings:

	For the Year Ended December 31,
	2004	2003	2002
	(In Millions)
Inter-company lease transactions   related to computer services	$   0.9	$ -	$ -
Inter-company lease transactions related   to facility and building maintenance	1.0	-	-
Money pool interest income	.1	.1	.2
Money pool interest expense	$  (0.6)	$ -	$ -

     As of December 31, 2004 and 2003, Pepco had the following material balances due to and from related parties:

	2004	2003
	(In Millions)
Payable to Related Party (current)
PHI Service Company	$(12.9)	$(14.1)
Pepco Energy Services(a)	(12.5)	(10.2)
Money Pool Balance with Pepco Holdings	$(14.0)	$(57.8)

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

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(13)QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

     The quarterly data presented below reflect all adjustments necessary in the opinion of management for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations, differences between summer and winter rates and the scheduled downtime and maintenance of electric generating units.

	2004
	First Quarter	SecondQuarter	Third  Quarter	Fourth  Quarter	Total
	(Millions of Dollars)
Total Operating Revenue	$369.6	$461.2	$575.5	$399.6	$1,805.9
Total Operating Expenses	334.6	397.6	468.9	378.6	1,579.7
Operating Income	35.0	63.6	106.6	21.0	226.2
Other Expenses	(19.3)	(18.7)	(17.4)	(17.5)	(72.9)
Income Before Income Tax Expense	15.7	44.9	89.2	3.5	153.3
Income Tax Expense (Benefit)	6.2	18.8	33.2	(1.5)	56.7
Net Income	9.5	26.1	56.0	5.0	96.6
Dividends on Preferred Stock	.4	.4	.1	.1	1.0
Earnings Available for Common Stock	$  9.1	$ 25.7	$ 55.9	$  4.9	$   95.6

	2003
	First Quarter	SecondQuarter	Third  Quarter		Fourth  Quarter	Total
	(Millions of Dollars)
Total Operating Revenue	$333.4	$370.1	$518.4		$326.1	$1,548.0
Total Operating Expenses	280.2	309.8	407.0	(a)	301.9	1,298.9
Operating Income	53.2	60.3	111.4		24.2	249.1
Other Expenses	(18.3)	(16.2)	(16.6)		(19.7)	(70.8)
Distributions on Preferred Securities of   Subsidiary Trust	2.3	2.3	-		-	4.6
Income Before Income Tax Expense	32.6	41.8	94.8		4.5	173.7
Income Tax Expense	12.6	17.2	38.7		0.6	69.1
Net Income	20.0	24.6	56.1		3.9	104.6
Dividends on Preferred Stock	1.2	1.3	0.4		0.4	3.3
Earnings Available for Common Stock	$ 18.8	$ 23.3	$ 55.7		$  3.5	$  101.3

NOTE:	Sales of electric energy are seasonal and, accordingly, comparisons by quarter within a year are not meaningful.
(a)	Includes a $14.5 million pre-tax ($8.7 million after-tax) net reserve recorded against a delinquent receivable from Mirant.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors
of Delmarva Power & Light Company:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Delmarva Power & Light Company (a wholly owned subsidiary of Pepco Holdings, Inc.) and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2)presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financia l statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it accounts for financial instruments with characteristics of both liabilities and equity as of July 1, 2003.

As discussed in Note 14, the consolidated financial statements for the year ended December 31, 2003 have been restated.

PricewaterhouseCoopers LLP
Washington, DC
March 16, 2005

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DELMARVA POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF EARNINGS
For the Year Ended December 31,	2004	2003	2002
(Millions of Dollars)
Operating Revenue
Electric	$1,017.6	$1,062.7	$1,050.9
Natural Gas	227.7	191.0	178.1
Total Operating Revenue	1,245.3	1,253.7	1,229.0
Operating Expenses
Fuel and purchased energy	656.8	699.5	677.0
Gas purchased	162.5	132.3	124.9
Other operation and maintenance	179.1	186.9	189.0
Merger-related costs	-	-	9.7
Depreciation and amortization	73.9	73.7	82.1
Other taxes	27.6	35.9	35.5
Gain on sale of assets	-	-	(11.6)
Total Operating Expenses	1,099.9	1,128.3	1,106.6
Operating Income	145.4	125.4	122.4
Other Income (Expenses)
Interest and dividend income	0.4	0.8	4.9
Interest expense	(33.0)	(37.0)	(43.5)
Other income	7.6	8.0	9.8
Other expenses	(4.4)	(4.8)	(4.5)
Total Other Expenses	(29.4)	(33.0)	(33.3)
Distributions on Preferred Securities of Subsidiary Trust	-	2.8	5.7
Income Before Income Tax Expense	116.0	89.6	83.4
Income Taxes	49.7	36.4	33.7
Net Income	66.3	53.2	49.7
Dividends on Preferred Stock	1.0	1.0	1.7
Earnings Available for Common Stock	$   65.3	$   52.2	$   48.0
The accompanying Notes are an integral part of these Consolidated Financial Statements. 285 _________________________________________________________________________________

DELMARVA POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS
	December 31, 2004	December 31, 2003
ASSETS
(Millions of Dollars)
CURRENT ASSETS
Cash and cash equivalents	$    3.7	$    4.9
Restricted cash	4.8	-
Accounts receivable, less allowance for uncollectible      accounts of $8.7 million and $10.1 million	169.7	164.3
Fuel, materials and supplies - at average cost	38.4	34.2
Prepaid expenses and other	11.6	13.3
Total Current Assets	228.2	216.7
INVESTMENTS AND OTHER ASSETS
Goodwill	48.5	48.5
Regulatory assets	140.3	135.0
Prepaid pension costs	204.7	195.4
Other	29.8	33.5
Total Investments and Other Assets	423.3	412.4
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	2,303.4	2,195.0
Accumulated depreciation	(755.0)	(687.0)
Net Property, Plant and Equipment	1,548.4	1,508.0
TOTAL ASSETS	$2,199.9	$2,137.1
The accompanying Notes are an integral part of these Consolidated Financial Statements. 286 _____________________________________________________________________________

DELMARVA POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER'S EQUITY	December 31, 2004	December 31, 2003
(Millions of Dollars, except share data)
CURRENT LIABILITIES
Short-term debt	$  137.0	$  174.4
Accounts payable and accrued liabilities	54.7	52.7
Accounts payable due to associated companies	46.3	36.9
Capital lease obligations due within one year	.2	.2
Taxes accrued	6.6	17.2
Interest accrued	6.3	5.8
Other	60.9	43.2
Total Current Liabilities	312.0	330.4
DEFERRED CREDITS
Regulatory liabilities	220.6	222.8
Income taxes	430.9	379.1
Investment tax credits	11.7	12.6
Above-market purchased energy contracts and other       electric restructuring liabilities	30.6	42.7
Other	32.5	31.6
Total Deferred Credits	726.3	688.8
LONG-TERM LIABILITIES
Long-term debt	539.6	442.7
Debentures issued to Financing Trust	-	72.2
Capital lease obligations	.2	.4
Total Long-Term Liabilities	539.8	515.3
COMMITMENTS AND CONTINGENCIES (NOTE 11)
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	223.5
Capital stock expense	(10.0)	(10.0)
Retained income	364.7	367.4
Total Shareholder's Equity	600.1	580.9
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$2,199.9	$2,137.1
The accompanying Notes are an integral part of these Consolidated Financial Statements. 287 _____________________________________________________________________________

DELMARVA POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Year Ended December 31,	2004	Restated   See Note (14) 2003		2002
(Millions of Dollars)
OPERATING ACTIVITIES
Net income	$ 66.3		$ 53.2		$ 49.7
Adjustments to reconcile net income to net cash    from operating activities:
Depreciation and amortization	73.9		73.7		82.1
Gain on divestiture of generation assets	-		-		(11.6)
Deferred income taxes	66.5		28.3		67.8
Investment tax credit adjustments, net	(0.9)		(1.0)		(0.9)
Prepaid pension costs	(9.3)		(2.6)		(10.2)
Other post-retirement benefit obligation	-		-		(0.4)
Regulatory assets and liabilities	(9.1)		(10.4)		45.6
Changes in:
Accounts receivable	(4.1)		5.6		18.1
Fuel, materials and supplies	(4.2)		(8.8)		4.6
Accounts payable and accrued liabilities	10.7		1.5		(6.2)
Interest and taxes accrued	11.8		(25.9)		(54.6)
Energy trading contracts	(3.9)		(14.4)		(15.6)
Prepaid expenses and other	1.0		(0.1)		(1.4)
Other deferred credits	1.9		2.3		(3.5)
Other deferred charges	(0.3)		2.9		(5.9)
Net Cash From Operating Activities	200.3		104.3		157.6
INVESTING ACTIVITIES
Net investment in property, plant and equipment	(115.2)		(98.7)		(82.5)
Proceeds from/changes in:
Divestiture of generation assets	-		-		10.0
Sale of other assets	-		-		0.8
Restricted cash	(4.8)		-		-
Net other investing activities	(1.1)		0.2		0.2
Net Cash Used By Investing Activities	(121.1)		(98.5)		(71.5)
FINANCING ACTIVITIES
Common dividends paid	(68.0)		(49.1)		(62.8)
Preferred dividends paid	(1.0)		(1.0)		(1.7)
Redemption of preferred stock	-		-		(7.9)
Redemption of debentures issued to financing trust	(70.0)		-		-
Long-term debt issued	100.0		33.2		46.0
Long-term debt redeemed	(7.0)		(153.4)		(121.5)
Net change in short-term debt	(33.2)		62.6		-
Principal portion of capital lease payments	(0.2)		(0.1)		(0.1)
Costs of issuances and refinancings	(1.0)		(2.8)		(3.3)
Net Cash Used By Financing Activities	(80.4)		(110.6)		(151.3)
Net Decrease In Cash and Cash Equivalents	(1.2)		(104.8)		(65.2)
Cash and Cash Equivalents at Beginning of Year	4.9		109.7		174.9
CASH AND CASH EQUIVALENTS AT END OF YEAR	$  3.7		$  4.9		$109.7
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest (net of     capitalized interest of $.3 million,     $.3 million, and $.6 million), and     (received) paid for income taxes:
Interest	$ 29.3		$ 37.1		$ 39.3
Income taxes	$ (3.4)		$ 22.1		$ 11.9
NONCASH ACTIVITIES
Capital contribution in respect of     certain intercompany transactions	$ 21.9		$    -		$    -
The accompanying Notes are an integral part of these Consolidated Financial Statements. 288 _____________________________________________________________________________

DELMARVA POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
	Common Stock		Premium on Stock	Capital Stock Expense	Retained Income
	Shares	Par Value
(Dollar Amounts in Millions)
BALANCE, DECEMBER 31, 2001	1,000	$-	$223.5	$(10.1)	$364.9
Net Income	-	-	-	-	49.7
Dividends:
Preferred stock	-	-	-	-	(1.7)
Common stock	-	-	-	-	(48.5)
BALANCE, DECEMBER 31, 2002	1,000	$-	$223.5	$(10.1)	$364.4
Net Income	-	-	-	-	53.2
Dividends:
Preferred stock	-	-	-	-	(1.0)
Common stock	-	-	-	-	(49.1)
Redemption of preferred stock	-	-	-	0.1	(0.1)
BALANCE, DECEMBER 31, 2003	1,000	$-	$223.5	$(10.0)	$367.4
Net Income	-	-	-	-	66.3
Capital contribution	-	-	21.9	-	-
Dividends:
Preferred stock	-	-	-	-	(1.0)
Common stock	-	-	-	-	(68.0)
BALANCE, DECEMBER 31, 2004	1,000	$-	$245.4	$(10.0)	$364.7
The accompanying Notes are an integral part of these Consolidated Financial Statements. 289 _____________________________________________________________________________

NOTES TO CONSOLIDATED 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. 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. On August 1, 2002, Pepco completed its acquisition of Conectiv, at which time Pepco and Conectiv became wholly owned subsidiaries of Pepco Holdings, Inc. (Pepco Holdings or PHI). 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.

     DPL continues as a wholly owned, direct subsidiary of Conectiv. The Maryland Public Service Commission (MPSC) and the Delaware Public Service Commission (DPSC) issued orders on April 11, 2002 and April 16, 2002, respectively, approving the acquisition of Conectiv by Pepco. The orders issued by the DPSC and MPSC required approximately $1.5 million of contributions to certain funds.

     DPL's operating results for 2002 included costs related to the acquisition of Conectiv by Pepco of $9.7 million ($5.8 million after income taxes). The $9.7 million of costs included the following: (i) $8.2 million for severances and stock options settled in cash; and (ii) $1.5 million for contributions to certain funds based on the terms of orders issued by the MPSC and DPSC, as noted above. Based on the terms of the settlement agreements and commission orders in the States having regulatory jurisdiction over DPL, none of the costs related to the acquisition of Conectiv by Pepco are recoverable in future customer rate increases. Such costs are, and will be, excluded from studies submitted in base rate filings.

(2)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation Policy

     The accompanying consolidated financial statements include the accounts of DPL and its wholly owned subsidiaries. All intercompany balances and transactions between subsidiaries have been eliminated. DPL uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies where it holds a 20% to 50% voting interest and cannot exercise control over the operations and policies of the investment. Under the equity method, DPL records its interest in the entity as an investment in the accompanying Consolidated Balance Sheets, and its percentage share of the entity's earnings are recorded in the accompanying Consolidated Statements of Income.

     In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46) issued in January 2003, with a revised interpretation issued in December 2003, FASB Interpretation No. 46-R "Consolidation of Variable Interest Entities" (FIN 46R), DPL deconsolidated its trust preferred securities that had previously been consolidated. FIN 46 and FIN 46R address

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conditions when an entity should be consolidated based upon variable interests rather than voting interests. For additional information regarding the impact of implementing FIN 46 and FIN 46R, refer to the FIN 46 section later in this Note to the consolidated financial statements.

Use of Estimates

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America, such as Statement of Position 94-6 "Disclosure of Certain Significant Risks and Uncertainties," requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Examples of significant estimates used by DPL include the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, fair value calculations (based on estimating market pricing) associated with derivative instruments, pension assumptions, and judgment involved with assessing the probability of recovery of regulatory assets. Although DPL believes that its estimates and assumptions are reasonable, they are based upon in formation presently available. Actual results may differ significantly from these estimates.

Regulation of Power Delivery Operations

     Certain aspects of DPL's utility businesses are subject to regulation by DPSC and MPSC, and the Virginia State Corporation Commission (VSCC), and its wholesale operations are subject to regulation by the Federal Energy Regulatory Commission (FERC).

     Based on the regulatory framework in which it has operated, DPL has historically applied, and in connection with its transmission and distribution business continues to apply, the provisions of Statement of Financial Accounting Standards No. 71 (SFAS No. 71) "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 allows regulated entities, in appropriate circumstances, to establish regulatory assets and to defer the income statement impact of certain costs that are expected to be recovered in future rates. Management's assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders, and other factors. Should existing facts or circumstances change in the future to indicate that a regulatory asset is not probable of recovery, then the regulatory asset would be charged to earnings.

     The components of DPL's regulatory asset balances at December 31, 2004 and 2003 are as follows:

	2004	2003
	(Millions of Dollars)
Deferred energy supply costs	$  17.7	$   7.3
Deferred recoverable income taxes	83.5	89.0
Deferred debt extinguishment costs	17.6	18.0
Unrecovered purchased power contracts	9.4	12.2
Other	12.1	8.5
Total regulatory assets	$140.3	$ 135.0

     The components of DPL's regulatory liability balances at December 31, 2004 and 2003 are as follows:

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	2004	2003
(Millions of Dollars)
Deferred income taxes due to customers	$ 39.0	$ 39.3
Removal costs	176.8	181.5
Other	4.8	2.0
Total regulatory liabilities	$220.6	$222.8

     A description of the regulatory assets and regulatory liabilities is as follows:

     Deferred Energy Supply Costs: Primarily represents deferred costs relating to the provision of Basic Generation Service (BGS) and other restructuring related costs incurred by DPL. Also includes deferred fuel costs for DPL's gas business. All deferrals receive a return. The deferred fuel costs are recovered annually.

     Deferred Recoverable Income Taxes:Represents deferred income tax assets recognized from the normalization of flow-through items as a result of amounts previously provided to customers. As temporary differences between the financial statement and tax basis of assets reverse, deferred recoverable income taxes are amortized. There is no return on these deferrals.

     Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period. A return is received on these deferrals.

     Unrecovered Purchased Power Contracts: Represents deferred costs related to purchase power contracts at DPL which are being recovered over 9 years and earn a return.

     Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 2 years and generally do not receive a return.

     Deferred Income Taxes Due to Customers: Represents the portion of deferred income tax liabilities applicable to DPL's utility operations that has not been reflected in current customer rates, for which future payment to customers is probable. As temporary differences between the financial statement and tax basis of assets reverse, deferred recoverable income taxes are amortized.

     Removal Costs: Represents DPL's asset retirement obligation associated with removal costs accrued using Commission approved depreciation rates for transmission, distribution and general utility property. In accordance with SFAS No. 143, accruals for removal costs were classified as a regulatory liability.

Revenue Recognition

     DPL recognizes revenues for the supply and delivery of electricity and gas upon delivery to the customer, including amounts for services rendered, but not yet billed. DPL recorded amounts for unbilled revenue of $66.2 million and $57.8 million as of December 31, 2004 and 2003, respectively. These amounts are included in the "accounts receivable" line item in the accompanying consolidated balance sheets. Similarly, revenues from other

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services are recognized when services are performed or products are delivered. Revenues from non-regulated electricity and gas sales are included in "Electric" revenues and "Gas" revenues, respectively. Additionally, the collection of taxes related to the consumption of electricity and gas by its customers, such as fuel, energy, or other similar taxes are components of the Company's tariffs and as such, are billed to customers and recorded in Operating Revenues. Payments of these taxes by the Company are recorded in Other Taxes. Excise tax related generally to the consumption of gasoline by the Company in the normal course of business is charged to operations, maintenance or construction, and is de minimis.

Income Taxes

     DPL, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL based upon the taxable income or loss, determined on a separate return basis.

     The Consolidated Financial Statements include current and deferred income taxes. Current income taxes represent the amounts of tax expected to be reported on DPL's state income tax returns and the amount of federal income tax allocated from Pepco Holdings. Deferred income taxes are discussed below.

     Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement and tax basis of existing assets and liabilities and are measured using presently enacted tax rates. The portion of DPL's deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in "regulatory assets" on the Consolidated Balance Sheets. For additional information, see the discussion under "Regulation of Power Delivery Operations," shown above.

     Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

     Investment tax credits from utility plant purchased in prior years are reported on the Consolidated Balance Sheets as "Investment tax credits." These investment tax credits are being amortized to income over the useful lives of the related utility plant.

Accounting for Derivatives

     DPL uses derivative instruments (forward contracts, futures, swaps, and exchange-traded and over-the-counter options) primarily to reduce gas commodity price volatility while limiting its firm customers' exposure to increases in the market price of gas. DPL also manages commodity risk with physical natural gas and capacity contracts that are not classified as derivatives. The primary goal of these activities is to reduce the exposure of its regulated retail gas customers to natural gas price fluctuations. All premiums paid and other transaction costs incurred as part of DPL's natural gas hedging activity, in addition to all gains and losses, are fully recoverable through the fuel adjustment clause approved by the DPSC and are deferred under SFAS No. 71 until recovered. At December 31, 2004, there was a deferred derivative liability on DPL's balance sheet of $1.5 million, and a negative adjustment balance for the fair value hedge of $1.1 mil lion, offset by a $2.6 million regulatory asset.

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Accounts Receivable and Allowance for Uncollectible Accounts

     DPL's accounts receivable balances primarily consist of customer accounts receivable, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period, but not billed to the customer until a future date, usually within one month. The Company uses the allowance method to account for uncollectible accounts receivable.

Capitalized Interest and Allowance for Funds Used During Construction

     In accordance with the provisions of SFAS No. 34, "Capitalization of Interest Cost," the cost of financing the construction of DPL's electric generating plants is capitalized. Other non-utility construction projects also include financing costs in accordance with SFAS No. 34. The cost of additions to, and replacements or betterments of, retirement units of property and plant is capitalized. Such costs include material, labor, the capitalization of an Allowance for Funds Used During Construction (AFUDC) and applicable indirect costs, including engineering, supervision, payroll taxes and employee benefits.

     DPL recorded AFUDC for borrowed funds of $.3 million, $.3 million, and $.6 million for the years ended December 31, 2004, 2003, and 2002, respectively. These amounts are recorded as a reduction of "interest expense" in the accompanying consolidated statements of earnings.

     DPL recorded amounts for AFUDC equity income of $.4 million, $.5 million and $.9 million for the years ended December 31, 2004, 2003 and 2002, respectively. The amounts are included in the "other income" caption of the accompanying consolidated statements of earnings.

Amortization of Debt Issuance and Reacquisition Costs

     The amortization of debt discount, premium, and expense, including deferred debt extinguishment costs associated with the regulated electric and gas transmission and distribution businesses, is included in interest expense.

Accounting for Goodwill

     Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. The accounting for goodwill is governed by SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 requires business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting and broadens the criteria for recording intangible assets apart from goodwill. SFAS No. 142 requires that purchased goodwill and certain indefinite-lived intangibles no longer be amortized, but instead be tested for impairment.

Goodwill Impairment Evaluation

     The provisions of SFAS No. 142 require the evaluation of goodwill for impairment at least annually or more frequently if events and circumstances indicate that the asset might be impaired. Examples of such events and circumstances include an adverse action or assessment by a regulator, a significant adverse change in legal factors or in the business climate, and unanticipated competition. SFAS No. 142 indicates that if the fair value of a reporting unit is less than its carrying value, including goodwill, an impairment charge may be necessary. During 2004 DPL tested its goodwill for

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impairment as of July 1, 2004. This testing concluded that none of DPL's goodwill balance was impaired.

Long Lived Asset Impairment Evaluation

     DPL is required to evaluate certain long-lived assets (for example, generating property and equipment and real estate) to determine if they are impaired when certain conditions exist. SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets," provides the accounting for impairments of long-lived assets and indicates that companies are required to test long-lived assets for recoverability whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or if there is a significant adverse change in the manner an asset is being used or its physical condition.

     For long-lived assets that are expected to be held and used, SFAS No. 144 requires that an impairment loss shall only be recognized if the carrying amount of an asset is not recoverable and exceeds its fair value. For long-lived assets that can be classified as assets to be disposed of by sale under
SFAS No. 144, an impairment loss shall be recognized to the extent their carrying amount exceeds their fair value, including costs to sell.

Pension and Other Post Retirement Plans

     Pepco Holdings sponsors a retirement plan that covers substantially all employees of Pepco, Conectiv and certain employees of other Pepco Holdings' subsidiaries (Retirement Plan). Following the consummation of the acquisition of Conectiv by Pepco on August 1, 2002, the Pepco General Retirement Plan and the Conectiv Retirement Plan were merged into the Retirement Plan on December 31, 2002. The provisions and benefits of the merged Retirement Plan for Pepco employees are identical to those of the original Pepco plan and for Conectiv employees the provisions and benefits of the merged Retirement Plan are identical to the original Conectiv plan. Pepco Holdings also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans. In addition to sponsoring non-contributory retirement plans, Pepco Holdings provides certain post-retirement health care and life insurance benefits fo r eligible retired employees.

     The Company accounts for the Retirement Plan in accordance with SFAS No. 87, "Employers' Accounting for Pensions" and its other post-retirement benefits in accordance with SFAS No. 106, "Employers' Accounting for Post-retirement Benefits Other Than Pensions." DPL's financial statement disclosures were prepared in accordance with SFAS No. 132, "Employers' Disclosures about Pensions and Other Post-retirement Benefits."

Property, Plant and Equipment

     Property, plant and equipment are recorded at cost. The carrying value of property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable under the provisions of SFAS No. 144. Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation. For additional information regarding the treatment of retirement obligations, refer to the "Asset Retirement Obligations" section included in this Note to the consolidated financial statements.

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     The annual provision for depreciation on electric and gas property, plant and equipment is computed on the straight-line basis using composite rates by classes of depreciable property. Accumulated depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. The relationship of the annual provision for depreciation for financial accounting purposes to average depreciable property was 3.1% for 2004, 3.1% for 2003, and 3.2% for 2002. Property, plant and equipment other than electric and gas facilities is generally depreciated on a straight-line basis over the useful lives of the assets.

Cash and Cash Equivalents

     Cash and cash equivalents include cash on hand, money market funds, and commercial paper with original maturities of three months or less. Additionally, deposits in PHI's "money pool," which PHI and certain of its subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.

Restricted Cash

     Restricted cash represents cash either held as collateral or pledged as collateral and is restricted from use for general corporate purposes.

Asset Retirement Obligations

     DPL adopted Financial Accounting Standards Board (FASB) Statement No. 143 entitled "Accounting for Asset Retirement Obligations," (SFAS No. 143) on January 1, 2003. This Statement establishes the accounting and reporting standards for measuring and recording asset retirement obligations. Based on the implementation of SFAS No. 143, at December 31, 2004 and 2003, $176.9 million and $181.5 million in asset removal costs have been classified as a regulatory liability in the accompanying Consolidated Balance Sheets.

SFAS 150

     Effective July 1, 2003, DPL implemented SFAS No. 150 entitled "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS No. 150). This Statement established standards for how an issuer classifies and measures, in its Consolidated Balance Sheet, certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 resulted in DPL's reclassification (initially as of September 30, 2003) of its "Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Which Holds Solely Parent Junior Subordinated Debentures" (TOPrS) on its Consolidated Balance Sheet to a long term liability classification. Additionally, in accordance with the provisions of SFAS No. 150, dividends on the TOPrS declared subsequent to the July 1, 2003 implementation of SFAS No. 150, are recorded as interest expense in DPL's Consolidated Statement of Earnings for the years end ed December 31, 2004 and 2003. In accordance with the transition provisions of SFAS No. 150, amounts prior to 2003 were not reclassified.

     In December 2003, the FASB deferred for an indefinite period the application of the guidance in SFAS No. 150 to non-controlling interests that are classified as equity in the financial statements of a subsidiary but would be classified as a liability in the parent's financial statements under SFAS No. 150. The deferral is limited to mandatorily redeemable non-controlling interests associated with finite-lived subsidiaries. DPL does not have an

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interest in any such applicable entities as of December 31, 2004 and 2003, but will continue to evaluate the applicability of this deferral to entities which may be consolidated as a result of FASB Interpretation No. 46, "Consolidation of Variable Interest Entities."

FIN 45

     DPL applied the provisions of FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45), commencing in 2003 to its agreements that contain guarantee and indemnification clauses. These provisions expand those required by FASB Statement No. 5, "Accounting for Contingencies," by requiring a guarantor to recognize a liability on its balance sheet for the fair value of obligations it assumes under certain guarantees issued or modified after December 31, 2002 and to disclose certain types of guarantees, even if the likelihood of requiring the guarantor's performance under the guarantee is remote.

     As of December 31, 2004 and 2003, DPL did not have material obligations under guarantees or indemnifications issued or modified after December 31, 2002, that are required to be recognized as a liability on its consolidated balance sheets.

FIN 46

     On December 31, 2003, FIN 46 was implemented by DPL. FIN 46 was revised and superseded by FASB Interpretation No. 46 (revised December 2003), "Consolidation of Variable Interest Entities" (FIN 46R) which clarified some of the provisions of FIN 46 and exempted certain entities from its requirements. The implementation of FIN 46R did not impact DPL's financial condition or results of operations for the years ended December 31, 2004 and 2003.

Other Non-Current Assets

     The other assets balance principally consists of real estate under development, equity and other investments, and deferred compensation trust assets.

Other Current Liabilities

     The other current liability balance principally consists of customer deposits, accrued vacation liability, and the current portion of deferred income taxes.

Other Deferred Credits

     The other deferred credits balance principally consists of miscellaneous deferred liabilities.

Reclassifications

     Certain prior year amounts have been reclassified in order to conform to current year presentations.

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(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)  LEASING ACTIVITIES

     DPL leases an 11.9% interest in the Merrill Creek Reservoir. The lease is an operating lease and payments over the remaining lease term, which ends in 2032, are $122.4 million in aggregate. DPL also has long-term leases for certain other facilities and equipment. Minimum commitments as of December 31, 2004, under the Merrill Creek Reservoir lease and other lease agreements are as follows: 2005-$8.6 million; 2006-$8.6 million; 2007-$8.6 million; 2008-$9.4 million; 2009-$9.4 million; beyond 2009-$106.8 million; total-$151.4 million.

(5)  PROPERTY, PLANT AND EQUIPMENT

     Property, plant and equipment is comprised of the following:

At December 31, 2004	Original   Cost	AccumulatedDepreciation	Net    Book Value
	(Millions of Dollars)
Distribution	$1,172.1	$356.2	$  815.9
Transmission	512.4	186.2	326.2
Gas	326.7	93.8	232.9
General	168.0	81.3	86.7
Construction work in progress	71.4	-	71.4
Non-operating and other property	52.8	37.5	15.3
Total	$2,303.4	$755.0	$1,548.4
At December 31, 2003
Distribution	$1,144.2	$ 332.8	$  811.4
Transmission	498.6	173.6	325.0
Gas	314.5	80.7	233.8
General	132.9	67.6	65.3
Construction work in progress	53.0	-	53.0
Non-operating and other property	51.8	32.3	19.5
Total	$2,195.0	$687.0	$1,508.0

     The balances of all property, plant and equipment, which are primarily electric transmission and distribution property, are stated at original cost. Utility plant is generally subject to a first mortgage lien.

(6)  PENSIONS AND OTHER POST-RETIREMENT BENEFITS

Pension Benefits

     Pepco Holdings sponsors a retirement plan that covers substantially all employees of Pepco, Conectiv and certain employees of other Pepco Holdings' subsidiaries (Retirement Plan). Following the consummation of the acquisition of Conectiv by Pepco on August 1, 2002, the Pepco General Retirement Plan and the Conectiv Retirement Plan were merged into the Retirement Plan on December 31, 2002. The provisions and benefits of the merged Retirement Plan for Pepco employees are identical to those of the

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original Pepco plan and for Conectiv employees the provisions and benefits are identical to those of the original Conectiv plan. Pepco Holdings also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans. Pepco Holdings uses a December 31 measurement date for its plans.

     The acquisition of Conectiv by Pepco in August 2002 resulted in purchase accounting requirements that are reflected in the net periodic pension cost. Under this accounting treatment, Conectiv's accrued pension liability was adjusted on August 1, 2002 through consolidation to recognize all previously unrecognized gains and losses arising from past experience different from that assumed, all unrecognized prior service costs, and the remainder of any unrecognized obligation or asset existing at the date of the initial application of SFAS No.87, "Employers' Accounting for Pensions." The Conectiv Retirement Plan transferred a projected benefit obligation of $804 million and plan assets of $744 million on August 1, 2002.

     Plan assets are stated at their market value as of the measurement date, December 31. All dollar amounts in the following tables are in millions of dollars.

     The following tables provide a roll forward of the changes in the projected benefit obligation and plan assets for the most recent two years.

	Pension Benefits
Change in Benefit Obligation	2004	2003
Benefit obligation at beginning of year	$1,579.2	$1,398.9
Service cost	35.9	33.0
Interest cost	94.7	93.7
Actuarial loss	51.4	144.4
Benefits paid	(113.2)	(90.8)
Benefit obligation at end of year	$1,648.0	$1,579.2
Change in Plan Assets
Fair value of plan assets at beginning of year	$1,462.8	$1,240.6
Actual return on plan assets	161.1	261.5
Company contributions	12.8	51.5
Benefits paid	(113.2)	(90.8)
Fair value of plan assets at end of year	$1,523.5	$1,462.8

     The following table provides a reconciliation of the projected benefit obligation, plan assets and funded status of the plans.

	Pension Benefits
	2004	2003
Fair value of plan assets at end of year	$1,523.5	$1,462.8
Benefit obligation at end of year	1,648.0	1,579.2
Funded status (plan assets less than plan obligations)	$(124.5)	$(116.4)
Amounts not recognized:
Unrecognized net actuarial loss	261.2	253.3
Unrecognized prior service cost	3.0	4.0
Net amount recognized	$ 139.7	$ 140.9

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     The following table provides a reconciliation of the amounts recognized in PHI's Consolidated Balance Sheets as of December 31:

	Pension Benefits
	2004	2003
Prepaid benefit cost	$165.7	$166.6
Accrued benefit cost	(26.0)	(25.7)
Additional minimum liability for nonqualified plan	(7.0)	-
Intangible assets for nonqualified plan	.1	-
Accumulated other comprehensive income for   nonqualified plan	6.9	-
Net amount recognized	$139.7	$140.9

     The accumulated benefit obligation for the Retirement Plan (the qualified defined benefit pension plan) was $1,462.9 million and $1,409.0 million at December 31, 2004, and 2003, respectively. The table below provides the projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the PHI nonqualified pension plan with an accumulated benefit obligation in excess of plan assets at December 31, 2004.

	Pension Benefits
	2004	2003
Projected benefit obligation for nonqualified plan	$35.3	$34.3
Accumulated benefit obligation for nonqualified plan	$32.9	$24.0
Fair value of plan assets for nonqualified plan	-	-

     In 2004, PHI was required to recognize an additional minimum liability and an intangible asset related to its nonqualified pension plan as prescribed by SFAS No. 87. The liability was recorded as a reduction to shareholders' equity (other comprehensive income), and the equity will be restored to the balance sheet in future periods when the accrued benefit liability exceeds the accumulated benefit obligation at future measurement dates. The amount of reduction to shareholders' equity (net of income taxes) in 2004 was $4.1 million. The recording of this reduction did not affect net income or cash flows in 2004 or compliance with debt covenants.

	Pension Benefits
Other additional information:	2004	2003
Decrease in other comprehensive income	$4.1	-

     The table below provides the components of net periodic benefit costs recognized for the years ended December 31. A portion of the net periodic benefit cost is capitalized within PHI's Consolidated Balance Sheets.

Components of Net Periodic Benefit Cost
	Pension Benefits
	2004	2003	2002
Service cost	$  35.9	$  33.0	$  16.0
Interest cost	94.7	93.7	54.1
Expected return on plan assets	(124.2)	(106.2)	(69.0)
Amortization of prior service cost	1.1	1.0	1.0
Amortization of net (gain) loss	6.5	13.9	6.9
Net periodic benefit cost	$  14.0	$  35.4	$  9.0

     The 2004 net periodic benefit cost of $14.0 million includes $(8.7) million for DPL. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries.

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     The 2003 net periodic benefit cost of $35.4 million includes $(1.8) million for DPL. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries.

     The 2002 net periodic benefit cost amount of $9.0 million includes $(3.3) million for DPL. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries. DPL's annual net periodic benefit for 2002 was $(9.4) million.

     The following weighted average assumptions were used to determine the benefit obligations at December 31:

Assumptions
Weighted-average assumptions used to determine benefit obligations at December 31
	Pension Benefits
	2004	2003
Discount rate	5.875%	6.25%
Rate of compensation increase	4.50%	4.50%

     The following weighted average assumptions were used to determine the net periodic benefit cost for years ended December 31:

Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31
	Pension Benefits
	2004	2003
Discount rate	6.25%	6.75%
Expected long-term return on plan assets	8.75%	8.75%
Rate of compensation increase	4.50%	4.50%

     In selecting an expected rate of return on plan assets, PHI considers actual historical returns, economic forecasts and the judgment of its investment consultants on expected long-term performance for the types of investments held by the plan. The plan assets consist of equity and fixed income investments, and when viewed over a long time horizon, are expected to yield a return on assets of 8.75%.

Plan Assets

     Pepco Holdings' pension plan weighted-average asset allocations at December 31, 2004, and 2003, by asset category are as follows:

Asset Category	Plan Assets at December 31 2004      2003		Target Plan Asset Allocation	Minimum/ Maximum
Equity securities	66%	64%	60%	55% - 65%
Debt securities	33%	35%	35%	30% - 50%
Other	1%	1%	5%	0% - 10%
Total	100%	100%	100%

     In developing an asset allocation policy for its Retirement Plan, PHI examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, PHI examined the risk/return tradeoffs of alternative asset classes and asset mixes given long-term

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historical relationships, as well as prospective capital market returns. PHI also conducted an asset/liability study to match projected asset growth with projected liability growth and provide sufficient liquidity for projected benefit payments. By incorporating the results of these analyses with an assessment of its risk posture, and taking into account industry practices, PHI developed its asset mix guidelines. Under these guidelines, PHI diversifies assets in order to protect against large investment losses and to reduce the probability of excessive performance volatility while maximizing return at an acceptable risk level. Diversification of assets is implemented by allocating monies to various asset classes and investment styles within asset classes, and by retaining investment management firm(s) with complementary investment philosophies, styles and approaches. Based on the assessment of demographics, actuarial/funding, and business and financial charac teristics, PHI believes that its risk posture is slightly below average relative to other pension plans. Consequently, Pepco Holdings believes that a slightly below average equity exposure (i.e., a target equity asset allocation of 60%) is appropriate for the Retirement Plan.

     On a periodic basis, Pepco Holdings reviews its asset mix and rebalances assets back to the target allocation over a reasonable period of time.

     No Pepco Holdings common stock is included in pension program assets.

Cash Flows

Contributions

     Pepco Holdings, Inc. funding policy with regard to the Retirement Plan is to maintain a funding level in excess of 100% with respect to its accumulated benefit obligation (ABO). PHI's Retirement Plan defined benefit plan currently meets the minimum funding requirements of ERISA without any additional funding. In 2004 and 2003, PHI made discretionary tax-deductible cash contributions to the plan of $10.0 million and $50.0 million, respectively, in line with its funding policy. Assuming no changes to the current pension plan assumptions, PHI projects no funding will be required under ERISA in 2005; however, PHI may elect to make a discretionary tax-deductible contribution, if required to maintain its plan assets in excess of its ABO.

Expected Benefit Payments

     The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid from the Retirement Plan:

Years	Pension       Benefits
2005	$ 89.4
2006	91.6
2007	102.0
2008	108.2
2009	113.4
2010-2014	619.7

Other Post-Retirement Benefits

     In addition to sponsoring non-contributory retirement plans, Pepco Holdings provides certain post-retirement health care and life insurance benefits for eligible retired employees. Certain groups of employees hired January 1, 2005 or later will not have company subsidized retiree medical coverage; however, they will be able to purchase coverage at full cost

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through the company. Pepco Holdings uses a December 31 measurement date for its plans.

     The acquisition of Conectiv by Pepco in August 2002 resulted in purchase accounting requirements that are reflected in the net periodic benefit cost. Under this accounting treatment, Conectiv's accrued post-retirement health care and life insurance liability was adjusted on August 1, 2002 through consolidation to recognize all previously unrecognized actuarial gains and losses, all unrecognized prior service costs, and the remainder of any unrecognized obligation or asset existing at the date of the initial application of SFAS No. 106. The Conectiv Plan transferred a projected benefit obligation of $320 million and plan assets of $100 million on August 1, 2002.

     During 2004, PHI announced amendments to its post-retirement health care plans for certain groups of eligible employees. The amendments included changes to coverage and retiree cost-sharing, and are reflected as a reduction in PHI's 2004 net periodic benefit cost and a reduction of $42 million in projected benefit obligation at December 31, 2004.

     Plan assets are stated at their market value as of the measurement date, December 31. All dollar amounts in the following tables are in millions of dollars.

     The following tables provide a roll forward of the changes in the benefit obligation and plan assets for the most recent two years: 

	Other Post- Retirement Benefits
	2004	2003
Change in Benefit Obligation
Benefit obligation at beginning of year	$ 511.9	$ 472.4
Service cost	8.6	9.4
Interest cost	35.4	32.9
Amendments	(42.4)	-
Actuarial loss	117.0	31.0
Benefits paid	(37.0)	(33.8)
Benefit obligation at end of year	$ 593.5	$ 511.9
Change in Plan Assets
Fair value of plan assets at beginning of year	$ 145.2	$ 123.0
Actual return on plan assets	15.7	25.8
Company contributions	41.0	30.2
Benefits paid	(37.0)	(33.8)
Fair value of plan assets at end of year	$ 164.9	$ 145.2

     The following table provides a reconciliation of benefit obligations, plan assets and funded status of the plans:

	Other Post- Retirement Benefits
	2004	2003
Fair value of plan assets at end of year	$164.9	$145.2
Benefit obligation at end of year	593.5	511.9
Funded status (plan assets less than plan obligations)	(428.6)	(366.7)
Amounts not recognized:
Unrecognized net actuarial loss	188.5	89.0
Unrecognized initial net obligation	(29.5)	10.8
Net amount recognized	$(269.6)	$(266.9)

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     The following table provides a reconciliation of the amounts recognized in PHI's Consolidated Balance Sheets as of December 31:

	Other Post- Retirement Benefits
	2004	2003
Prepaid benefit cost	$     -	$     -
Accrued benefit cost	(269.6)	(266.9)
Net amount recognized	$(269.6)	$(266.9)

     The table below provides the components of net periodic benefit costs recognized for the years ended December 31. A portion of the net periodic benefit cost is capitalized within PHI's Consolidated Balance Sheets.

Components of Net Periodic Benefit Cost
	Other Post- Retirement Benefits
	2004	2003	2002
Service cost	$ 8.6	$ 9.5	$ 7.2
Interest cost	35.4	32.9	20.0
Expected return on plan assets	(9.9)	(8.3)	(5.2)
Recognized actuarial loss	9.5	8.0	6.1
Net periodic benefit cost	$43.6	$42.1	$28.1

     The 2004 net periodic benefit cost amount of $43.6 million, includes $9.5 million for DPL. The remaining net periodic benefit cost is related to other PHI subsidiaries. The 2003 net periodic benefit cost amount of $42.1 million, includes $9.0 million for DPL. The remaining net periodic benefit cost is related to other PHI subsidiaries. The 2002 net periodic benefit cost amount of $28.1 million includes $2.1 million of DPL. The remaining 2002 net periodic benefit cost is related to other PHI subsidiaries. DPL's annual net periodic benefit cost for 2002 was $6.4 million.

     The following weighted average assumptions were used to determine the benefit obligations at December 31:

Assumptions
Weighted-average assumptions used to determine benefit obligations at December 31
	Other Post- Retirement Benefits
	2004	2003
Discount rate	5.875%	6.25%
Rate of compensation increase	4.50%	4.50%

     The following weighted average assumptions were used to determine the net periodic benefit cost for years ended December 31:

Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31
	Other Post- Retirement Benefits
	2004	2003
Discount rate	6.25%	6.75%
Expected long-term return on plan assets	8.75%	8.75%
Rate of compensation increase	4.50%	4.50%

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     In selecting an expected rate of return on plan assets, PHI considers actual historical returns, economic forecasts and the judgment of its investment consultants on expected long-term performance for the types of investments held by the plan. The plan assets consist of equity and fixed income investments, and when viewed over a long time horizon, are expected to yield a return on assets of 8.75%.

     The table below provides the assumed health care trend rates as of December 31:

Assumed health care cost trend rates at December 31
	2004	2003
Health care cost trend rate assumed for next year	9%	8%
Rate to which the cost trend rate is assumed to   decline (the ultimate trend rate)	5%	5%
Year that the rate reaches the ultimate trend rate	2009	2007

     Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1-Percentage- Point Increase	1-Percentage- Point Decrease
Effect on total of service and interest cost	$ 1.8	$ (1.7)
Effect on post-retirement benefit obligation	25.0	(23.0)

Plan Assets

     Pepco Holdings' post-retirement plan weighted-average asset allocations at December 31, 2004, and 2003, by asset category are as follows:

	Plan Assets    at December 31,    2004         2003
Asset Category
Equity securities	65%	63%
Debt securities	35%	37%
Total	100%	100%

     No Pepco Holdings common stock is included in post-retirement program assets.

Cash Flows

Contributions

     DPL funded a portion of its estimated post-retirement liability through the use of its IRC 501(c)(9) Voluntary Employee Beneficiary Association (VEBA). In 2004 and 2003, DPL contributed $9.5 million and $9.0 million, respectively, to the plans, and assuming no changes to the current pension plan assumptions, expects similar amounts to be contributed in 2005.

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Expected Benefit Payments

     The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Years	Pension       Benefits
2005	$ 36.0
2006	36.3
2007	38.6
2008	40.6
2009	42.4
2010-2014	225.3

     FASB Staff Position (FSP 106-2), Accounting and Disclosure
       Requirements Related to the Medicare Prescription Drug, Improvement
       and Modernization Act of 2003

     The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) became effective on December 8, 2003. The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

     Pepco Holdings sponsors post-retirement health care plans that provide prescription drug benefits. Pepco Holdings did not elect the deferral of appropriate accounting permitted by the FASB Staff position (FSP) 106-1. The Accumulated Post-retirement Benefit Obligation (APBO) as of December 31, 2004 and December 31, 2003 has been reduced by $28 million to reflect the effects of the Act. This reduction includes both the decrease in the cost of future benefits being earned and an amortization of the APBO reduction over the future average working lifetime of the participants, or 12 years.The anticipated claims costs expected to be incurred have been adjusted to reflect the cost sharing between Medicare and Pepco Holdings. Participation rates have not been changed. In reflecting the effects of the Act, Pepco Holdings has determined which plans are eligible for Medicare cost sharing by analyzing the terms of each of its plans. It has rec ognized Medicare cost sharing for a plan only if Pepco Holdings' projected prescription drug coverage is expected to be at least as generous as the expected contribution by Medicare to a prescription drug plan not provided by Pepco Holdings.

     The effect of the subsidy on the 2004 other post-retirement net periodic benefit cost of $43.6 million is approximately a $3.6 million reduction due to the subsidy. Approximately $2.0 million is related to the amortization of the actuarial gain, and approximately $1.6 million is a subsidy-related reduction in interest cost on the APBO.

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(7)  LONG-TERM DEBT

     Long-term debt outstanding as of December 31, 2004 and 2003 is presented below:

Type of Debt	Interest Rates	Due	2004	2003
			(Dollars in Millions)
First Mortgage Bonds:
	7.71%	2025	$100.0	$100.0
Amortizing First Mortgage Bonds	6.95%	2004-2008	13.2	15.7
			113.2	115.7
Unsecured Tax-Exempt Bonds:
	5.20%	2019	31.0	31.0
	3.15%	2023 (c)	18.2	18.2
	5.50%	2025 (a)	15.0	15.0
	4.90%	2026 (b)	34.5	34.5
	5.65%	2028 (a)	16.2	16.2
	Variable	2030-2038	93.4	93.4
			208.3	208.3
Medium-Term Notes (unsecured):
	8.30%	2004	-	4.5
	6.75%	2006	20.0	20.0
	7.06%-8.13%	2007	61.5	61.5
	7.56%-7.58%	2017	14.0	14.0
	6.81%	2018	4.0	4.0
	7.61%	2019	12.0	12.0
	7.72%	2027	10.0	10.0
			121.5	126.0
Notes (unsecured):
	5.0%	2014	100.0	-
Total long-term debt			543.0	450.0
Unamortized premium and discount, net			(0.7)	(0.3)
Current portion of long-term debt (d)			(2.7)	(7.0)
Total net long-term debt			$539.6	$442.7

(a)  The bonds are subject to mandatory tender on July 1, 2010.

(b)  The bonds are subject to mandatory tender on May 1, 2011.

(c)  The bonds are subject to mandatory tender on August 1, 2008.

(d)  Included in short-term debt on the accompanying consolidated balance sheets.

     The outstanding First Mortgage Bonds issued by DPL are secured by a lien on substantially all of the issuing company's property, plant and equipment.

     The debentures issued to the financing trust were redeemed during 2004 and totaled $72.2 million at December 31, 2003.

     Maturities of long-term debt and sinking fund requirements during the next five years are as follows: 2005-$2.7 million; 2006-$22.9 million; 2007-$64.7 million; 2008-$4.4 million; zero in 2009; and thereafter $448.3 million.

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SHORT-TERM DEBT

     DPL, a regulated utility, has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. A detail of the components of DPL's short-term debt at December 31, 2004 and 2003 is as follows.

	2004	2003
	(Millions of Dollars)
Commercial paper	$    -	$    -
Inter-Company borrowings	29.5	62.6
Variable rate demand bonds	104.8	104.8
Current portion of long-term debt	2.7	7.0
Total	$137.0	$174.4

Commercial Paper

     DPL maintains an ongoing commercial paper program of up to $275 million. The commercial paper notes can be issued with maturities up to 270 days from the date of issue. The commercial paper program is backed by $500 million in credit facilities, shared with Pepco and ACE. DPL's credit limit under the facilities is the lower of $300 million and the maximum amount of short-term debt authorized by the applicable regulatory authority, except that the aggregate amount of credit utilized by Pepco, DPL and ACE at any given time under these facilities may not exceed $500 million.

     DPL had no commercial paper outstanding at December 31, 2004 and December 31, 2003. The interest rate for commercial paper issued during 2004 was 1.10%. Interest rates for commercial paper issued during 2003 ranged from 1.05% to 1.22%. Maturities were less than 270 days for all commercial paper issued.

Variable Rate Demand Bonds

     Variable Rate Demand Bonds ("VRDB") are included in short-term debt because the VRDB are due on demand by the bondholder. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. DPL expects the bonds submitted for purchase will continue to be remarketed successfully due to its credit worthiness and the bonds' interest rates being set at market rates. DPL may also utilize one of the fixed rate/fixed term conversion options of the bonds. Thus, DPL considers the VRDB to be a source of long-term financing. The VRDB outstanding in 2004 and 2003 mature in 2017 ($26.0 million), 2024 ($33.3 million), 2028 ($15.5 million) and 2029 ($30.0 million). Interest rates ranged from 1.04% to 2.47% in 2004 and .60% to 1.90% in 2003.

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Credit Facility Agreements

     In July 2004, Pepco Holdings, Pepco, DPL and ACE entered into a five-year credit agreement with an aggregate borrowing limit of $650 million. This agreement replaced a $550 million 364-day credit agreement that was entered into on July 29, 2003. The respective companies also are parties to a three-year credit agreement that was entered into in July 2003 and terminates in July 2006 with an aggregate borrowing limit of $550 million. Pepco Holdings' credit limit under these facilities is $700 million, and the credit limit of each of Pepco, DPL and ACE under these facilities is the lower of $300 million and the maximum amount of short-term debt authorized by the appropriate state commission, except that the aggregate amount of credit utilized by Pepco, DPL and ACE at any given time under these facilities may not exceed $500 million. Funds borrowed under these facilities are available for general corporate purposes. Either credit facility also can be used as credit support for the commercial paper programs of the respective companies. The three-year and five-year credit agreements contain customary financial and other covenants that, if not satisfied, could result in the acceleration of repayment obligations under the agreements or restrict the ability of the companies to borrow under the agreements. Among these covenants is 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 agreements. As of December 31, 2004, the applicable ratios for Pepco Holdings, Pepco, DPL and ACE were 59.0%, 58.5%, 52.1% and 50.2%, respectively. The credit agreements also contain a number of customary events of default that could result in the acceleration of repayment obligations under the agreements, including (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 agreements) of Pepco Holdings or the failure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE.

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(8)  INCOME TAXES

     DPL, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL pursuant to a written tax sharing agreement which was approved by the SEC as part of Pepco's acquisition of Conectiv on August 1, 2002. Under this tax sharing agreement, PHI's consolidated federal income tax liability is allocated based upon PHI's and its subsidiaries' separate taxable income or loss, with the exception of the tax benefits applicable to non-acquisition debt expenses of PHI. Such tax benefits are allocated to subsidiaries with taxable income.

     The provision for income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred tax liabilities (assets) are shown below.

Components of Consolidated Income Tax Expense
		2004	2003	2002
		(Dollars in Millions)
Federal:	Current	$(14.7)	$10.2	$(26.7)
	Deferred	54.7	19.3	54.1
State:	Current	(1.2)	(1.1)	(6.5)
	Deferred	11.8	9.0	13.7
Investment tax credit amortization		(0.9)	(1.0)	(0.9)
Total Income Tax Expense		$49.7	$36.4	$ 33.7

Reconciliation of Effective Income Tax Rate
	For the Year Ended December 31,
	2004		2003		2002
	Amount	Rate	Amount	Rate	Amount	Rate
	(Amounts in Millions)
Statutory federal    income tax expense	$40.6	35%	$31.4	35%	$29.2	35%
State income taxes, net    of federal benefit	6.9	6	5.2	6	4.7	6
Plant basis difference	1.5	1	-	-	-	-
Investment tax credit    amortization	(0.9)	(1)	(1.0)	(1)	(0.9)	(1)
Other, net	1.6	2	0.8	1	0.7	-
Income tax expense on   continuing operations	$49.7	43%	$36.4	41%	$33.7	40%

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Components of Deferred Income Taxes

The tax effects of temporary differences that give rise to DPL's net deferred tax liability are shown below. There were no valuation allowances for deferred tax assets as of December 31, 2004 and December 31, 2003.

	As of December 31,
	2004	2003
	(Dollars in Millions)
Deferred Tax Liabilities
Plant basis differences	$326.8	$294.3
Deferred recoverable income taxes	39.0	39.3
Prepaid pension costs	80.7	68.9
Other	26.7	40.8
Total deferred tax liabilities	473.2	443.3
Deferred Tax Assets
Deferred investment tax credits	4.6	4.9
Above-market purchased energy contracts     and other Electric restructuring liabilities	17.1	28.5
Other	18.0	37.5
Total deferred tax assets	39.7	70.9
Total net deferred tax liability	433.5	372.4
Add: current portion of deferred tax asset	(2.6)	6.7
Total deferred tax liability	$430.9	$379.1

Taxes Other Than Income Taxes

     Taxes, other than income taxes, charged to operating expense for each period are shown below.

	2004	2003	2002
Gross Receipts/Delivery	$15.5	$16.3	$16.4
Property	8.3	17.9	17.5
Environmental, Use and Other	3.8	1.7	1.6
Total	$27.6	$35.9	$35.5

(9)  PREFERRED STOCK

     The preferred stock amounts outstanding as of December 31, 2004 and 2003 are as follows:

		Shares Outstanding		December 31,
Series	Redemption Price	2004	2003	2004	2003
			(Dollars in Millions)
Redeemable Serial Preferred
$100 per share par value:      3.70%-5.00%	$103-$105	181,698	181,698	$18.2	$18.2
6.75% (1)	$100	35,000	35,000	3.5	3.5
				$21.7	$21.7

(1)   Redeemable as of November 1, 2003, at $100 per share.

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(10)FAIR VALUE OF FINANCIAL INSTRUMENTS

     The estimated fair values of DPL's financial instruments at December 31, 2004 and 2003 are shown below.

	2004		2003
	Carrying Amount	Fair Value	Carrying Amount	Fair Value
	(Dollars in Millions)
Long-term debt	$539.6	$568.6	$442.7	$483.2
Debentures issued to Financing Trust	$    -	$    -	$ 72.2	$ 70.8
Redeemable serial preferred stock	$ 21.7	$ 14.4	$ 21.7	$ 15.4

     The methods and assumptions below were used to estimate, at December 31, 2004 and 2003, the fair value of each class of financial instruments shown above for which it is practicable to estimate that value.

     The fair value of the Investments was derived based on quoted market prices.

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

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

     The carrying amounts of all other financial instruments in DPL's accompanying financial statements approximate fair value.

(11)  COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Rate Proceedings

     On October 1, 2004, DPL submitted its annual Gas Cost Rate (GCR) filing to the 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, on November 29, 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 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. A final order addressing both the Nov ember 1 and December 29 increases is expected in the spring of 2005.

     On February 13, 2004, DPL filed with the DPSC for a change in electric ancillary service rates that would have an aggregate effect of increasing annual Delaware electric revenues by $13.1 million or 2.4%. This filing was

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prompted by the increasing ancillary service costs charged to DPL by PJM. The proposed rates went into effect on March 15, 2004, subject to refund. On June 22, 2004, the DPSC approved a settlement agreement that provided for an increase having an aggregate effect of increasing annual Delaware electric revenues by $12.4 million, or 2.3%, with rates effective June 23, 2004. The approved increase was slightly less than the proposed increase that went into effect on March 15, 2004. As part of the settlement, the resulting estimated over-collection of $75,000 was given by DPL to the State of Delaware Low Income Fund administered by the Delaware Department of Human Services on July 15, 2004.

     In compliance with the settlement approved by the MPSC in connection with the merger of Pepco and Conectiv, on December 4, 2003, DPL submitted testimony and supporting schedules to review and reset if necessary its electricity distribution rates in Maryland to be effective July 1, 2004, when the then-current distribution rate freeze/caps ended. DPL's filing demonstrated that it was in an under-earning situation and, as allowed in the merger settlement, DPL requested that a temporary rate reduction implemented on July 1, 2003 for non-residential customers be terminated effective July 1, 2004. DPL estimated that the termination of the rate reduction would increase its annual revenues by approximately $1.1 million. A settlement reached between the parties allowing for this $1.1 million increase to be effective July 1, 2004 was approved by the MPSC in Order No. 79186. With limited exceptions, DPL cannot increase its distribution rates until Jan uary 1, 2007.

SOS and Default Service Proceedings

     Maryland

     Under a settlement approved by the MPSC in April 2003 addressing standard offer service (SOS) service in Maryland following the expiration of DPL's fixed-rate default supply obligations to non-residential customers in June 2004 and to residential customers through June 2004, DPL is required to provide default electricity supply at market rates to residential and small commercial customers through May 2008, to medium-sized commercial customers through May 2006, and to large commercial customers through May 2005. In accordance with the settlement, DPL purchases the power supply required to satisfy its market rate default supply obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved and supervised by the MPSC. DPL is entitled to recover from its default supply customers the costs of the default supply plus an average margin of $0.002 per kilowatt hour, calculated based on total sal es to residential, small, and large commercial Maryland SOS customers over the twelve months ended December 31, 2003. Because margins vary by customer class, the actual average margin over any given time period will depend on the number of Maryland SOS customers from each customer class and the load taken by such customers over the time period.

     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 VSCC. DPL currently obtains all of the energy and capacity needed to fulfill its default service obligations in Virginia under a supply agreement with a subsidiary of Conectiv Energy Holding Company (the subsidiaries of Conectiv Energy Holding Company are referred to as Conectiv Energy). A prior agreement, also with Conectiv Energy terminated effective

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December 31, 2004. The current contract was entered into after conducting a competitive bid procedure identical to the Maryland SOS process in most respects and Conectiv Energy was the lowest bidder to provide wholesale power supply for DPL's Virginia default service customers. The new supply agreement commenced January 1, 2005 and expires in May 2006. On October 26, 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 dated November 17, 2004 allowed DPL to put interim rates into effect on January 1, 2005, subject to refund if the VSCC subsequently determines the rate is excessive. The interim rates reflected an increase of 1.0247 cents per 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 17 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 Office of Attorney General. The VSCC ruled on January 18, 2005, that the administrative charge and margin are base rate items not recoverable through a fuel clause. No appeal is planned regarding this filing. A settlement resolving all other issues and m aking the interim rates final was filed on March 4, 2005, contingent only on possible future adjustment depending on the result of a related proceeding at FERC. A hearing is scheduled for March 16, 2005, and the VSCC is expected to approve the settlement.

     Also in October, DPL and Conectiv Energy jointly filed an application with the VSCC under Virginia's Affiliates Act requesting authorization for DPL to enter into a contract to purchase power from an affiliate. This authorization permits the contract to be executed with an affiliate, but is not a ruling on the merits of the contract. A VSCC order dated December 17, 2004 granted approval for DPL to purchase power from Conectiv Energy under the new contract according to its terms beginning January 1, 2005.

     On October 29, 2004, Conectiv Energy made a filing with FERC requesting authorization to enter into a contract to supply power to an affiliate. On December 30, 2004, FERC granted the requested authorization effective January 1, 2005, subject to refund and hearings on the narrow question whether, in 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 unduly favored Conectiv Energy in the credit criteria and analysis applied. DPL cannot predict the outcome of this proceeding.

     Delaware

     Under a settlement approved by the DPSC, DPL is required to provide default electricity supply to customers in Delaware until May 1, 2006. On October 19, 2004, the DPSC initiated a proceeding to investigate and determine which entity should act as the standard offer supplier in DPL's Delaware service territory after May 1, 2006, and what prices should be charged for SOS after May 1, 2006. Similar to the process used in Maryland, 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 will resolve issues relating to the process under which supply will be acquired by the SOS provider and way in which SOS prices will be set and

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monitored. In the last stage, 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 February 22, 2005, the DPSC voted to approve an SOS process that will allow a Wholesale Standard Offer Service Model with DPL as the SOS Provider. Issues including the length of this extension and any profit margin that DPL may be able to earn and retain in conjunction with this service have been deferred for further discussion and will be decided by the DPSC at a later date. A written DPSC order documenting this decision is expected sometime in March or April 2005.

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 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 (CERCLA) at the Diamond State Salvage site in Wilmington, Delaware. In the context of the negotiations, DOJ informed DPL that DPL is a de minimis party at the site. In February 2005, DPL entered into a de minimis consent decree with the United States which, if approved by the U.S. District Court, would require DPL to pay $144,000 as reimbursement of the government's response costs, resolve DPL's alleged liability, and provide DPL a covenant not to sue from the United States and protection from third-party claims for contribution.

     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. DPL expects to complete the RI/FS in the first 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 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

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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 1999, DPL entered into a de minimis settlement with EPA and paid approximately $107,000 to resolve its liability for cleanup costs at the 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.

(12)  RELATED PARTY TRANSACTIONS

     PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including DPL. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries' share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated in consolidation and no profit results from these transactions. PHI Service Company costs directly charged or allocated to DPL for the years ended December 31, 2004, 2003 and 2002 were $98.4 million, $100.3 million and $102.6 million, respectively.

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

	For the Year Ended December 31,
	2004	2003	2002
	(In Millions)
Full Requirements Contract with Conectiv   Energy Supply for power, capacity and   ancillary services to service Provider   of Last Resort Load	$(510.5)	$(607.7)	$(600.0)
Standard Offer Service agreement   with Conectiv Energy Supply	(11.3)	-	-
Inter-company lease transactions   related to facilities	3.9	6.0	5.5
Inter-company lease transactions   related to computer services	2.2	2.4	3.1
Sublease of Merrill Creek Water Rights   to Conectiv Delmarva Generation	2.5	2.8	1.8
Money pool interest income	-	.8	4.5
Money pool interest expense	$  (1.1)	$     -	$     -

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     As of December 31, 2004 and 2003, DPL had the following balances due to and from related parties:

	2004	2003
	(In Millions)
Receivable from Related Party
King Street Assurance	$  6.7	$  6.7
Payable to Related Party (current)
PHI Service Company	(12.6)	(13.4)
Conectiv Energy Supply	(38.5)	(31.0)
Delmarva Operating Service Company	(2.4)	-
Money Pool Balance with Pepco Holdings	$(29.5)	$(62.6)

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(13)QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

     The quarterly data presented below reflect all adjustments necessary in the opinion of management for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations, differences between summer and winter rates and the scheduled downtime and maintenance of electric generating units.

	2004
	First Quarter	SecondQuarter	Third  Quarter	Fourth  Quarter	Total
	(Dollars in Millions)
Total Operating Revenue	$350.7	$297.6	$319.8	$277.2	$1,245.3
Total Operating Expenses	304.7	256.3	288.1	250.8	1,099.9
Operating Income	46.0	41.3	31.7	26.4	145.4
Other Expenses	(7.9)	(7.4)	(6.6)	(7.5)	(29.4)
Income Before Income Tax Expense	38.1	33.9	25.1	18.9	116.0
Income Taxes	15.7	14.0	11.0	9.0	49.7
Net Income	22.4	19.9	14.1	9.9	66.3
Dividends on Preferred Stock	.2	.3	.2	.3	1.0
Earnings Available for   Common Stock	$ 22.2	19.6	$ 13.9	$  9.6	$   65.3

	2003
	First Quarter	SecondQuarter	Third  Quarter	Fourth  Quarter	Total
	(Dollars in Millions)
Total Operating Revenue	$343.3	$288.5	$345.6	$276.3	$1,253.7
Total Operating Expenses	296.2	260.9	315.8	255.4	1,128.3
Operating Income	47.1	27.6	29.8	20.9	125.4
Other Expenses	(8.1)	(8.0)	(8.4)	(8.5)	(33.0)
Distributions on Preferred   Securities of Subsidiary Trust	1.4	1.4	-	-	2.8
Income Before Income Taxes	37.6	18.2	21.4	12.4	89.6
Income Taxes	15.0	7.0	8.4	6.0	36.4
Net Income	22.6	11.2	13.0	6.4	53.2
Dividends on Preferred Stock	.2	.3	.3	.2	1.0
Earnings Available for   Common Stock	$ 22.4	$ 10.9	$ 12.7	$  6.2	$   52.2

Note: Sales of electric energy are seasonal and, accordingly, comparisons within a year are not meaningful.

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(14)  RESTATEMENT

     The purpose of the restatement was to correct an error in DPL's Consolidated Statements of Cash Flows. PHI maintains a pool of funds, referred to as a "money pool," as a mechanism for managing the short-term cash requirements of its utility subsidiaries. DPL is a participant in the money pool. DPL was in an investment position in the money pool for the first three quarters of 2003. During the fourth quarter of 2003, DPL borrowed funds from the money pool and at December 31, 2003, was in a $62.6 million borrowing position. This transaction was properly recorded on DPL's Consolidated Balance Sheets at December 31, 2003, as short-term debt. However, the borrowing activity was improperly classified in DPL's Consolidated Statements of Cash Flows at December 31, 2003, as a change in Accounts Payable, rather than as a financing activity. This error has been corrected in the Consolidated Statements of Cash Flows by correcting the line item am ounts as follows:

	Year Ended December 31, 2003
Caption on Consolidated Statements of Cash Flows	As Previously Reported	Adjustments	As Restated
	(Millions of Dollars)
Adjustments to reconcile net income to net cash from (used by) operating activities:
Changes in:
Accounts payable and accrued        liabilities	65.1	(62.6)	2.5
Net Cash From Operating Activities	166.9	(62.6)	104.3
Net Change in Short Term Debt	*	62.6	62.6
Net Cash Used by Financing Activities	(173.2)	62.6	(110.6)
* Not originally included as a caption

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THIS PAGE LEFT INTENTIONALLY BLANK.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors
of Atlantic City Electric Company:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Atlantic City Electric Company (a wholly owned subsidiary of Pepco Holdings, Inc.) and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2)presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial st atement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it accounts for financial instruments with characteristics of both liabilities and equity as of July 1, 2003.

PricewaterhouseCoopers LLP
Washington, DC
March 16, 2005

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF EARNINGS
For the Year Ended December 31,	2004	2003	2002
(Millions of Dollars)
Operating Revenue	$1,333.2	$1,236.0	$1,084.7
Operating Expenses
Fuel and purchased energy	806.7	778.7	682.5
Other operation and maintenance	192.7	208.0	243.6
Merger related costs	-	-	38.1
Depreciation and amortization	132.8	112.5	69.2
Other taxes	20.1	23.8	24.8
Deferred electric service costs	36.3	(7.0)	(71.3)
Impairment losses	-	-	9.5
Gain on sale of assets	(14.7)	-	-
Total Operating Expenses	1,173.9	1,116.0	996.4
Operating Income	159.3	120.0	88.3
Other Income (Expenses)
Interest and dividend income	2.2	6.1	8.4
Interest expense	(60.7)	(62.8)	(54.2)
Other income	6.1	7.3	9.9
Other expenses	-	-	(.3)
Total Other Expenses	(52.4)	(49.4)	(36.2)
Distributions on Preferred Securities of Subsidiary Trust	-	1.8	7.6
Income Before Income Tax Expense	106.9	68.8	44.5
Income Tax Expense	42.3	27.3	16.3
Income Before Extraordinary Item	64.6	41.5	28.2
Extraordinary Item (net of tax of   $4.1 million for 2003)	-	5.9	-
Net Income	64.6	47.4	28.2
Dividends on Preferred Stock	0.3	0.3	0.7
Earnings Available for Common Stock	$   64.3	$   47.1	$   27.5
The accompanying Notes are an integral part of these Consolidated Financial Statements. 322 ________________________________________________________________________________

ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS
ASSETS	December 31, 2004	December 31, 2003
(Millions of Dollars)
CURRENT ASSETS
Cash and cash equivalents	$    4.2	$107.2
Restricted cash	13.7	15.2
Accounts receivable, less allowance for uncollectible      accounts of $4.5 million and $5.3 million	168.1	167.7
Fuel, materials and supplies - at average cost	38.1	34.3
Prepaid taxes and other	4.9	5.3
Total Current Assets	229.0	329.7
INVESTMENTS AND OTHER ASSETS
Regulatory assets	1,069.4	1,179.1
Restricted funds held by trustee	9.1	1.6
Other	24.1	24.6
Total Investments and Other Assets	1,102.6	1,205.3
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	1,819.1	1,831.6
Accumulated depreciation	(680.0)	(790.1)
Net Property, Plant and Equipment	1,139.1	1,041.5
TOTAL ASSETS	$2,470.7	$2,576.5
The accompanying Notes are an integral part of these Consolidated Financial Statements. 323 ____________________________________________________________________________

ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER'S EQUITY	December 31, 2004	December 31, 2003
(Millions of Dollars, except share data)
CURRENT LIABILITIES
Short-term debt	$  123.4	$   59.5
Debentures issued to financing trust	-	25.8
Accounts payable and accrued liabilities	76.7	81.9
Accounts payable to associated companies	12.4	12.6
Taxes accrued	21.3	21.7
Interest accrued	14.3	16.8
Other	35.6	39.7
Total Current Liabilities	283.7	258.0
DEFERRED CREDITS
Regulatory liabilities	44.6	51.0
Income taxes	496.0	514.7
Investment tax credits	19.7	24.4
Pension benefit obligation	44.0	37.1
Other post-retirement benefit obligation	44.7	43.6
Other	34.4	52.2
Total Deferred Credits	683.4	723.0
LONG-TERM LIABILITIES
Long-term debt	441.6	497.5
Transition Bonds issued by ACE Funding	523.3	551.3
Capital lease obligations	0.2	-
Total Long-Term Liabilities	965.1	1,048.8
COMMITMENTS AND CONTINGENCIES (NOTE 12)
REDEEMABLE SERIAL PREFERRED STOCK	6.2	6.2
SHAREHOLDER'S EQUITY
Common stock, $3.00 par value, authorized 25,000,000      shares, 8,546,017 and 12,886,853 shares outstanding,      respectively	25.6	38.7
Premium on stock and other capital contributions	294.0	343.0
Capital stock expense	(0.6)	(0.8)
Retained income	213.3	159.6
Total Shareholder's Equity	532.3	540.5
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$2,470.7	$2,576.5
The accompanying Notes are an integral part of these Consolidated Financial Statements. 324 ___________________________________________________________________________

ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Year Ended December 31,	2004	2003	2002
(Millions of Dollars)
OPERATING ACTIVITIES
Net income	$   64.6	$   47.4	$  28.2
Adjustments to reconcile net income to net cash    from operating activities:
Extraordinary item	-	(10.0)	-
Gain on sale of assets	(14.7)	-	-
Depreciation and amortization	132.8	112.5	69.2
Investment tax credit adjustments	(4.7)	(2.0)	(2.0)
Write-down of plant and property	-	-	9.5
Deferred income taxes	(18.4)	0.5	46.6
Regulatory assets and liabilities	32.5	(11.7)	(43.0)
Changes in:
Accounts receivable	(0.5)	(9.8)	3.3
Material and supplies	(3.8)	4.1	1.0
Prepaid New Jersey sales and excise taxes	(0.2)	(6.8)	(3.1)
Accounts payable accrued liabilities	(9.8)	(3.0)	56.5
Interest and taxes accrued	.5	45.5	15.0
Energy trading contracts	(0.3)	(15.4)	9.8
Other deferred charges	(8.1)	1.4	0.6
Other deferred credits	(4.8)	(3.0)	2.8
Other post-retirement benefit obligations	1.1	4.7	2.5
Prepaid pension costs	6.9	(9.5)	11.0
Net Cash From Operating Activities	173.1	144.9	207.9
INVESTING ACTIVITIES
Net investment in property, plant and equipment	(160.2)	(87.7)	(106.2)
Proceeds from/changes in:
Sale of other assets	11.0	-	12.4
Change in restricted cash	1.5	14.6	(21.5)
Other investing activities	-	(0.3)	(2.1)
Net Cash Used By Investing Activities	(147.7)	(73.4)	(117.4)
FINANCING ACTIVITIES
Common stock repurchased	(67.6)	(84.4)	-
Common dividends paid	(10.6)	(41.4)	(34.8)
Preferred dividends paid	(0.3)	(0.3)	(0.7)
Redemption of trust preferred stock	-	(70.0)	-
Redemption of debentures issued to financing trust	(25.0)	-	-
Redemption of preferred securities	-	-	(12.5)
Long-term debt issued	174.7	152.0	440.0
Long-term debt redeemed	(229.1)	(142.5)	(221.4)
Principal portion of capital lease payments	0.2	-	-
Net change in short-term debt	32.7	-	(45.0)
Costs of issuances and refinancings	(3.4)	(3.3)	(4.8)
Net Cash (Used By) From Financing Activities	(128.4)	(189.9)	120.8
Net (Decrease)/Increase In Cash and Cash Equivalents	(103.0)	(118.4)	211.3
Cash and Cash Equivalents at Beginning of Year	107.2	225.6	14.3
CASH AND CASH EQUIVALENTS AT END OF YEAR	$    4.2	$   107.2	$ 225.6
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest (net of capitalized     interest of $1.2 million, $.9 million, and     $1.4 million) and paid (received) for income taxes:
Interest	$  60.7	$  64.0	$  50.8
Income taxes	$  12.0	$  (4.1)	$ (43.8)
The accompanying Notes are an integral part of these Consolidated Financial Statements. 325 _____________________________________________________________________________

ATLANTIC CITY ELECTRIC COMPANY STATEMENTS OF SHAREHOLDER'S EQUITY
	Common Stock		Premium on Stock	Capital Stock Expense	Retained Income
	Shares	Par Value
(Dollar Amounts in Millions)
BALANCE, DECEMBER 31, 2001	18,320,937	$55.0	$411.5	$(1.3)	$156.2
Net Income	-	-	-	-	28.2
Dividends:	-	-	-	-
Preferred stock	-	-	-	-	(0.7)
Common stock	-	-	-	-	(29.7)
Preferred stock expense for redeemed    stock	-	-	-	0.1	(0.1)
BALANCE, DECEMBER 31, 2002	18,320,937	$55.0	$411.5	$(1.2)	$153.9
Net Income	-	-	-	-	47.4
Dividends:
Preferred stock	-	-	-	-	(0.3)
Common stock	-	-	-	-	(41.4)
Common stock repurchased	(5,434,084)	(16.3)	(68.5)	0.4	-
BALANCE, DECEMBER 31, 2003	12,886,853	$38.7	$343.0	$(0.8)	$159.6
Net Income	-	-	-	-	64.6
Dividends:
Preferred stock	-	-	-	-	(0.3)
Common stock	-	-	-	-	(10.6)
Common stock repurchased	(4,340,836)	(13.1)	(54.7)	0.2	-
Capital contribution	-	-	5.7	-	-
BALANCE, DECEMBER 31, 2004	8,546,017	$25.6	$294.0	$(0.6)	$213.3

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ATLANTIC CITY ELECTRIC COMPANY

(1)ORGANIZATION

     Atlantic City Electric Company (ACE) is engaged in the 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. On August 1, 2002 Pepco completed its acquisition of Conectiv, at which time Pepco and Conectiv became wholly owned subsidiaries of Pepco Holdings, Inc. (Pepco Holdings or PHI). 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.

     ACE continues as a wholly owned, direct subsidiary of Conectiv. ACE's operating results for 2002 include costs related to the acquisition of Conectiv by Pepco of $38.1 million ($22.6 million after income taxes). The $38.1 million of costs included the following: (i) a $30.5 million write-down of deferred electric service costs based on the terms of the Decision and Order issued by the New Jersey Board of Public Utilities (NJBPU) on July 3, 2002 that required ACE to forgo recovery of such costs effective upon the acquisition of Conectiv by Pepco; (ii) $6.6 million for severances and stock options settled in cash; and (iii) $1.0 million for a contribution to a certain fund based on the terms of an order issued by the NJBPU. Based on the terms of the settlement agreements and commission orders in the States having regulatory jurisdiction over ACE, none of the costs related to the acquisition of Conectiv by Pepco are recoverable in future custom er rate increases. Such costs are, and will be, excluded from studies submitted in base rate filings.

(2)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation Policy

     The accompanying consolidated financial statements include the accounts of ACE and its wholly owned subsidiaries. All intercompany balances and transactions between subsidiaries have been eliminated. ACE uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies where it holds a 20% to 50% voting interest and cannot exercise control over the operations and policies of the investment. Under the equity method, ACE records its interest in the entity as an investment in the accompanying Consolidated Balance Sheets, and its percentage share of the entity's earnings are recorded in the accompanying Consolidated Statements of Income. Additionally, the proportionate interests in jointly owned electric plants are consolidated.

     In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46) issued in January 2003, with a revised interpretation issued in December 2003, FASB Interpretation No. 46-R "Consolidation of Variable Interest Entities" (FIN 46R), ACE deconsolidated its trust preferred securities that had previously been consolidated. FIN 46 and FIN 46R address conditions when an entity should be consolidated based upon variable interests rather than voting interests. For additional information regarding the impact of implementing FIN 46 and FIN 46R, refer to the "New Accounting

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Standards Adopted" section later in this Note to the consolidated financial statements.

Use of Estimates

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America, such as Statement of Position 94-6 "Disclosure of Certain Significant Risks and Uncertainties," requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Examples of significant estimates used by ACE include the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, fair value calculations (based on estimating market pricing) associated with derivative instruments, pension assumptions, and judgment involved with assessing the probability of recovery of regulatory assets. Although ACE believes that its estimates and assumptions are reasonable, they are based upon in formation presently available. Actual results may differ significantly from these estimates.

Revenue Recognition

     ACE recognizes revenue for the supply and delivery of electricity upon delivery to the customer, including amounts for services rendered, but not yet billed. ACE recorded amounts for unbilled revenue of $57.2 million and $52.3 million as of December 31, 2004 and December 31, 2003. These amounts are included in the "accounts receivable" line item in the accompanying consolidated balance sheets. Additionally, the collection of taxes related to the delivery of electricity to its customers are components of the Company's tariffs and as such, are billed to customers and recorded in Operating Revenues. Payments of these taxes by the Company are recorded in Other Taxes. Excise tax related generally to the consumption of gasoline by the Company in the normal course of business is charged to operations, maintenance or construction, and is de minimis.

Regulation of Power Delivery Operations

     Certain aspects of ACE's utility businesses are subject to regulation by the NJBPU and its wholesale operations are subject to regulation by the Federal Energy Regulatory Commission (FERC).

     Based on the regulatory framework in which it has operated, ACE has historically applied, and in connection with its transmission and distribution business continues to apply, the provisions of Statement of Financial Accounting Standards No. 71 (SFAS No. 71) "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 allows regulated entities, in appropriate circumstances, to establish regulatory assets and to defer the income statement impact of certain costs that are expected to be recovered in future rates. Management's assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders, and other factors. Should existing facts or circumstances change in the future to indicate that a regulatory asset is not probable of recovery, then the regulatory asset would be charged to earnings.

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     The components of ACE's regulatory asset balances at December 31, 2004 and 2003 are as follows:

	2004	2003
	(Millions of Dollars)
Securitized stranded costs	$  887.7	$  945.4
Deferred energy supply costs	93.4	139.8
Deferred recoverable income taxes	13.3	16.4
Deferred debt extinguishment costs	17.8	16.0
Deferred other post-retirement benefit costs	20.0	22.5
Unrecovered purchased power contracts	13.2	14.1
Other	24.0	24.9
Total regulatory assets	$1,069.4	$1,179.1

     The components of ACE's regulatory liability balances at December 31, 2004 and 2003 are as follows:

	2004	2003
	(Millions of Dollars)
Stranded cost reserves	$   -	$ 7.2
Regulatory liability for Federal and New Jersey   tax benefit and other	44.6	43.8
Total regulatory liabilities	$44.6	$51.0

     A description of the regulatory assets and regulatory liabilities is as follows:

     Securitized Stranded Costs: Represents stranded costs associated with a non-utility generator (NUG) contract termination payment and the discontinuance of the application of SFAS No. 71 for ACE's electricity generation business. The recovery of these stranded costs has been securitized through the issuance of Transition Bonds by Atlantic City Electric Transition Funding LLC (ACE Funding). A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. Costs are amortized over the life of the Transition Bonds, which mature between 2010 and 2023.

     Deferred Energy Supply Costs: Primarily represents deferred costs relating to the provision of Basic Generation Service (BGS) and other restructuring related costs incurred by ACE. All deferrals receive a return. ACE deferrals are recoverable over the next 9 years.

     Deferred Recoverable Income Taxes:  Represents deferred income tax assets recognized from the normalization of flow-through items as a result of amounts previously provided to customers. As temporary differences between the financial statement and tax basis of assets reverse, deferred recoverable income taxes are amortized. There is no return on these deferrals.

     Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment for which recovery through regulated utility rates is considered probable and, if approved, will be amortized to interest expense during the authorized rate recovery period. A return is received on these deferrals.

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     Deferred Other Post-retirement Benefit Costs: Represents the non-cash portion of other post-retirement benefit costs deferred by ACE during 1993 through 1997. This cost is being recovered over a 15-year period that began on January 1, 1998. There is no return on this deferral.

     Unrecovered Purchased Power Contracts:  Represents deferred costs related to purchase power contracts at ACE which are being recovered over 3 years and earn a return.

     Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years and generally do not receive a return.

     Regulatory Liability for Federal and New Jersey Tax Benefit and Other: Securitized stranded costs include a portion of stranded costs attributable to the future tax benefit expected to be realized when the higher tax basis of the generating plants is deducted for New Jersey state income tax purposes as well as the future benefit to be realized through the reversal of federal excess deferred taxes. To account for the possibility that these tax benefits may be given to ACE's regulated electricity delivery customers through lower rates in the future, ACE established a regulatory liability. The regulatory liability related to federal excess deferred taxes will remain until such time as the Internal Revenue Service issues its final regulations with respect to normalization of these federal excess deferred taxes.

Cash and Cash Equivalents

     Cash and cash equivalents include cash on hand, money market funds, and commercial paper with original maturities of three months or less. Additionally, deposits in PHI's "money pool," which PHI and certain of its subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources. Deposits in the PHI money pool were $1.7 million and $103.0 million at December 31, 2004, and 2003, respectively.

Restricted Cash

     Restricted cash represents cash either held as collateral or pledged as collateral and is restricted from use for general corporate purposes.

Capitalized Interest and Allowance for Funds Used During Construction

     In accordance with the provisions of SFAS No. 34, "Capitalization of Interest Cost," the cost of financing the construction of ACE's subsidiaries electric generating plants is capitalized. Other non-utility construction projects also include financing costs in accordance with SFAS No. 34. The cost of additions to, and replacements or betterments of, retirement units of property and plant is capitalized. Such costs include material, labor, the capitalization of an Allowance for Funds Used During Construction (AFUDC) and applicable indirect costs, including engineering, supervision, payroll taxes and employee benefits.

     ACE recorded AFUDC for borrowed funds of $1.2 million, $.9 million and $1.4 million for the years ended December 31, 2004, 2003 and 2002, respectively. These amounts are recorded as a reduction of "interest expense" in the accompanying consolidated statements of earnings.

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     ACE recorded amounts for AFUDC equity income of $1.7 million, $1.2 million and $1.1 million for the years ended December 31, 2004, 2003 and 2002, respectively. The amounts are included in the "other income" caption of the accompanying consolidated statements of earnings.

Amortization of Debt Issuance and Reacquisition Costs

     The amortization of debt discount, premium, and expense, including deferred debt extinguishment costs associated with the regulated electric and gas transmission and distribution businesses, is included in interest expense.

Income Taxes

     ACE, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of Pepco Holdings. Federal income taxes are allocated to ACE based upon the taxable income or loss, determined on a separate return basis.

     The Consolidated Financial Statements include current and deferred income taxes. Current income taxes represent the amounts of tax expected to be reported on ACE's state income tax returns and the amount of federal income tax allocated from PHI. Deferred income taxes are discussed below.

     Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement and tax basis of existing assets and liabilities and are measured using presently enacted tax rates. The portion of ACE's deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in "regulatory assets" on the Consolidated Balance Sheets. For additional information, see the discussion under "Regulation of Power Delivery Operations," shown above.

     Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.

     Investment tax credits from utility plant purchased in prior years are reported on the Consolidated Balance Sheets as "Investment tax credits." These investment tax credits are being amortized to income over the useful lives of the related utility plant.

Pension and Other Post-Retirement Benefit Plans

     Pepco Holdings sponsors a retirement plan that covers substantially all employees of Pepco, Conectiv and certain employees of other Pepco Holdings' subsidiaries (Retirement Plan). Following the consummation of the acquisition of Conectiv by Pepco on August 1, 2002, the Pepco General Retirement Plan and the Conectiv Retirement Plan were merged into the Retirement Plan on December 31, 2002. The provisions and benefits of the merged Retirement Plan for Pepco employees are identical to those of the original Pepco plan and for Conectiv employees the provisions and benefits of the merged Retirement Plan are identical to the original Conectiv plan. Pepco Holdings also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans. In addition to sponsoring non-contributory retirement plans, Pepco Holdings provides certain post-retirement health care and life insurance benefits fo r eligible retired employees.

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     PHI accounts for the Retirement Plan in accordance with SFAS No. 87, "Employers' Accounting for Pensions" and its post-retirement health care and life insurance benefits for eligible employees in accordance with SFAS No. 106, "Employers' Accounting for Post-retirement Benefits Other Than Pensions." PHI's financial statement disclosures were prepared in accordance with SFAS No. 132, "Employers' Disclosures about Pensions and Other Post-retirement Benefits."

Long-Lived Asset Impairment Evaluation

     ACE is required to evaluate certain long-lived assets (for example, generating property and equipment and real estate) to determine if they are impaired when certain conditions exist. SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets," provides the accounting for impairments of long-lived assets and indicates that companies are required to test long-lived assets for recoverability whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or if there is a significant adverse change in the manner an asset is being used or its physical condition. For long-lived assets that are expected to be held and used, SFAS No. 144 requires that an impairment loss shall only be recognized if the carrying amount of an asset is not recoverable and exceeds its fair value.

Property, Plant and Equipment

     Property, plant and equipment are recorded at cost. The carrying value of property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable under the provisions of SFAS No. 144. Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation.

     The annual provision for depreciation on electric property, plant and equipment is computed on the straight-line basis using composite rates by classes of depreciable property. Accumulated depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. The relationship of the annual provision for depreciation for financial accounting purposes to average depreciable property was 3.3% for 2004, 3.2% for 2003, and 3.3% for 2002. Property, plant and equipment other than electric facilities is generally depreciated on a straight-line basis over the useful lives of the assets.

Accounts Receivable and Allowance for Uncollectible Accounts

     ACE's subsidiaries accounts receivable balances primarily consist of customer accounts receivable, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date, usually within one month. ACE uses the allowance method to account for uncollectible accounts receivable.

SFAS No. 150

     Effective July 1, 2003 ACE implemented SFAS No. 150 entitled "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS No. 150). This Statement established standards for how an issuer classifies and measures in its Consolidated Balance Sheet certain financial instruments with characteristics of both liabilities and equity.

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SFAS No. 150 resulted in ACE's reclassification (initially as of September 30, 2003) of its "Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Which Holds Solely Parent Junior Subordinated Debentures" (TOPrS) on its Consolidated Balance Sheet to a long term liability classification. Additionally, in accordance with the provisions of SFAS No. 150, dividends on the TOPrS declared subsequent to the July 1, 2003 implementation of SFAS No. 150, are recorded as interest expense in ACE's Consolidated Statement of Earnings for the years ended December 31, 2004 and 2003. In accordance with the transition provisions of SFAS No. 150, amounts prior to 2003 were not reclassified. In 2003, Atlantic Capital I redeemed all $70 million of its 8.25% Quarterly Income Preferred Securities at par.

     In December 2003, the FASB deferred for an indefinite period the application of the guidance in SFAS No. 150 to non-controlling interests that are classified as equity in the financial statements of a subsidiary but would be classified as a liability in the parent's financial statements under SFAS No. 150. The deferral is limited to mandatorily redeemable non-controlling interests associated with finite-lived subsidiaries. ACE does not have an interest in any such applicable entities as of December 31, 2004 and 2003, but will continue to evaluate the applicability of this deferral to entities which may be consolidated as a result of FASB Interpretation No. 46, "Consolidation of Variable Interest Entities."

FIN 45

     ACE applied the provisions of FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45), commencing in 2003 to its agreements that contain guarantee and indemnification clauses. These provisions expand those required by FASB Statement No. 5, "Accounting for Contingencies," by requiring a guarantor to recognize a liability on its balance sheet for the fair value of obligations it assumes under certain guarantees issued or modified after December 31, 2002 and to disclose certain types of guarantees, even if the likelihood of requiring the guarantor's performance under the guarantee is remote.

     As of December 31, 2004 and 2003, ACE did not have material obligations under guarantees or indemnifications issued or modified after December 31, 2002, that are required to be recognized as a liability on its consolidated balance sheets.

FIN 46

     On December 31, 2003, FIN 46 was implemented by ACE. FIN 46 was revised and superseded by FASB Interpretation No. 46 (revised December 2003), "Consolidation of Variable Interest Entities" (FIN 46R) which clarified some of the provisions of FIN 46 and exempted certain entities from its requirements. The implementation of FIN 46R (including the evaluation of interests in power purchase arrangements) did not impact ACE's financial condition or results of operations for the years ended December 31, 2004 and 2003.

     As part of its FIN 46R evaluation, ACE reviewed its power purchase agreements (PPAs), including its Non-Utility Generation (NUG) contracts, to determine (i) if its interest in each entity that is a counterparty to a PPA agreement was a variable interest, (ii) whether the entity was a variable interest entity and (iii) if so, whether ACE was the primary beneficiary. Due to a variable element in the pricing structure of PPAs with three

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entities, ACE potentially assumes the variability in the operations of the plants of these entities and therefore has a variable interest in the entities. However, due to ACE's inability to obtain information considered to be confidential and proprietary from certain of these entities or the certain entities' own determination that they qualified for exemption as a business, ACE was unable to obtain 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 these three entities in the years ended December 31, 2004, 2003, and 2002 were approximately $265 million, $247 million, and $241 million, respectively, of which $236 million, $220 million, and $221 million, respectively, related to purchases under the PPA agreements. ACE does not have exposure to loss under the PPA agreements since cost recovery will be achieved from its customers through regulated rates.

Other Non-Current Assets

     The other assets balance principally consists of real estate under development, equity and other investments, and deferred compensation trust assets.

Other Current Liabilities

     The other current liability balance principally consists of customer deposits, accrued vacation liability, and the current portion of deferred income taxes.

Other Deferred Credits

     The other deferred credits balance principally consists of miscellaneous deferred liabilities.

Reclassifications

     Certain prior year amounts have been reclassified in order to conform to current year presentations.

(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.

(4)  LEASING ACTIVITIES

     ACE leases other types of property and equipment for use in its operations. Amounts charged to operating expenses for these leases were $11.7 million in 2004, $10.0 million in 2003, and $9.2 million in 2002. Future minimum rental payments for all non-cancelable lease agreements are less than $10 million per year for each of the next five years.

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(5)  PROPERTY, PLANT AND EQUIPMENT

     Property, plant and equipment is comprised of the following:

At December 31, 2004		Original   Cost		AccumulatedDepreciation		Net    Book Value
		(Millions of Dollars)
Generation	$   73.5		$ 27.8		$   45.7
Distribution	1,039.4		416.7		622.7
Transmission	428.6		180.7		247.9
General	112.8		20.9		91.9
Construction work in progress	118.4		-		118.4
Non-operating and other property	46.4		33.9		12.5
Total	$1,819.1		$680.0		1,139.1
At December 31, 2003
Generation	$  213.6		$171.6		$   42.0
Distribution	1,027.3		411.5		615.8
Transmission	413.8		166.7		247.1
General	75.1		9.7		65.4
Construction work in progress	61.0		-		61.0
Non-operating and other property	40.8		30.6		10.2
Total	$1,831.6		$790.1		$1,041.5

     The balances of all property, plant and equipment, which is primarily electric transmission and distribution property, are stated at original cost. Utility plant is generally subject to a first mortgage lien.

Jointly Owned Plant

     ACE's Consolidated Balance Sheets include its proportionate share of assets and liabilities related to jointly owned plant. ACE has ownership interests in electric generating plants, transmission facilities, and other facilities in which various parties have ownership interests. ACE's proportionate share of operating and maintenance expenses of the jointly owned plant is included in the corresponding expenses in ACE's Consolidated Statements of Income. ACE is responsible for providing its share of financing for the jointly owned facilities. Information with respect to ACE's share of jointly owned plant as of December 31, 2004 is shown below.

Jointly Owned Plant	OwnershipShare	Megawatt CapabilityOwned	Plant inService	AccumulatedDepreciation	Construction Work inProgress
			(Dollars in Millions)
Coal-Fired Electric   Generating Plants
Keystone	2.47%	42	$19.7	$ 6.0	$0.6
Conemaugh	3.83%	65	37.5	13.1	0.3
Transmission Facilities	Various		24.9	13.6	-
Other Facilities	Various		1.1	0.3	-
Total			$83.2	$33.0	$0.9

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(6)  PENSIONS AND OTHER POST-RETIREMENT BENEFITS

Pension Benefits

     Pepco Holdings sponsors a retirement plan that covers substantially all employees of Pepco, Conectiv and certain employees of other Pepco Holdings' subsidiaries (Retirement Plan). Following the consummation of the acquisition of Conectiv by Pepco on August 1, 2002, the Pepco General Retirement Plan and the Conectiv Retirement Plan were merged into the Retirement Plan on December 31, 2002. The provisions and benefits of the merged Retirement Plan for Pepco employees are identical to those of the original Pepco plan and for Conectiv employees the provisions and benefits are identical to those of the original Conectiv plan. Pepco Holdings also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans. Pepco Holdings uses a December 31 measurement date for its plans.

     The acquisition of Conectiv by Pepco in August 2002 resulted in purchase accounting requirements that are reflected in the net periodic pension cost. Under this accounting treatment, Conectiv's accrued pension liability was adjusted on August 1, 2002 through consolidation to recognize all previously unrecognized gains and losses arising from past experience different from that assumed, all unrecognized prior service costs, and the remainder of any unrecognized obligation or asset existing at the date of the initial application of SFAS No.87, "Employers' Accounting for Pensions." The Conectiv Retirement Plan transferred a projected benefit obligation of $804 million and plan assets of $744 million on August 1, 2002.

     Plan assets are stated at their market value as of the measurement date, December 31. All dollar amounts in the following tables are in millions of dollars.

     The following tables provide a roll forward of the changes in the projected benefit obligation and plan assets for the most recent two years.

	Pension Benefits
Change in Benefit Obligation	2004	2003
Benefit obligation at beginning of year	$1,579.2	$1,398.9
Service cost	35.9	33.0
Interest cost	94.7	93.7
Actuarial loss	51.4	144.4
Benefits paid	(113.2)	(90.8)
Benefit obligation at end of year	$1,648.0	$1,579.2
Change in Plan Assets
Fair value of plan assets at beginning of year	$1,462.8	$1,240.6
Actual return on plan assets	161.1	261.5
Company contributions	12.8	51.5
Benefits paid	(113.2)	(90.8)
Fair value of plan assets at end of year	$1,523.5	$1,462.8

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     The following table provides a reconciliation of the projected benefit obligation, plan assets and funded status of the plans.

	Pension Benefits
	2004	2003
Fair value of plan assets at end of year	$1,523.5	$1,462.8
Benefit obligation at end of year	1,648.0	1,579.2
Funded status (plan assets less than plan obligations)	$(124.5)	$(116.4)
Amounts not recognized:
Unrecognized net actuarial loss	261.2	253.3
Unrecognized prior service cost	3.0	4.0
Net amount recognized	$ 139.7	$ 140.9

     The following table provides a reconciliation of the amounts recognized in PHI's Consolidated Balance Sheets as of December 31:

	Pension Benefits
	2004	2003
Prepaid benefit cost	$165.7	$166.6
Accrued benefit cost	(26.0)	(25.7)
Additional minimum liability for nonqualified plan	(7.0)	-
Intangible assets for nonqualified plan	.1	-
Accumulated other comprehensive income for   nonqualified plan	6.9	-
Net amount recognized	$139.7	$140.9

     The accumulated benefit obligation for the Retirement Plan (the qualified defined benefit pension plan) was $1,462.9 million and $1,409.0 million at December 31, 2004, and 2003, respectively. The table below provides the projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the PHI nonqualified pension plan with an accumulated benefit obligation in excess of plan assets at December 31, 2004.

	Pension Benefits
	2004	2003
Projected benefit obligation for nonqualified plan	$35.3	$34.3
Accumulated benefit obligation for nonqualified plan	$32.9	$24.0
Fair value of plan assets for nonqualified plan	-	-

     In 2004, PHI was required to recognize an additional minimum liability and an intangible asset related to its nonqualified pension plan as prescribed by SFAS No. 87. The liability was recorded as a reduction to shareholders' equity (other comprehensive income), and the equity will be restored to the balance sheet in future periods when the accrued benefit liability exceeds the accumulated benefit obligation at future measurement dates. The amount of reduction to shareholders' equity (net of income taxes) in 2004 was $4.1 million. The recording of this reduction did not affect net income or cash flows in 2004 or compliance with debt covenants.

	Pension Benefits
Other additional information:	2004	2003
Decrease in other comprehensive income	$4.1	-

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     The table below provides the components of net periodic benefit costs recognized for the years ended December 31. A portion of the net periodic benefit cost is capitalized within PHI's Consolidated Balance Sheets.

Components of Net Periodic Benefit Cost
	Pension Benefits
	2004	2003	2002
Service cost	$  35.9	$  33.0	$  16.0
Interest cost	94.7	93.7	54.1
Expected return on plan assets	(124.2)	(106.2)	(69.0)
Amortization of prior service cost	1.1	1.0	1.0
Amortization of net (gain) loss	6.5	13.9	6.9
Net periodic benefit cost	$  14.0	$  35.4	$  9.0

     The 2004 net periodic benefit cost of $14.0 million includes $7.1 million for ACE. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries.

     The 2003 net periodic benefit cost of $35.4 million includes $10.8 million for ACE. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries.

     The 2002 net periodic benefit cost amount of $9.0 million includes $4.9 million for ACE for the period August 1, 2002 to December 31, 2002. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries. ACE's annual net periodic benefit cost for 2002 was $11.3 million.

     The following weighted average assumptions were used to determine the benefit obligations at December 31:

Assumptions
Weighted-average assumptions used to determine benefit obligations at December 31
	Pension Benefits
	2004	2003
Discount rate	5.875%	6.25%
Rate of compensation increase	4.50%	4.50%

     The following weighted average assumptions were used to determine the net periodic benefit cost for years ended December 31:

Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31
	Pension Benefits
	2004	2003
Discount rate	6.25%	6.75%
Expected long-term return on plan assets	8.75%	8.75%
Rate of compensation increase	4.50%	4.50%

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     In selecting an expected rate of return on plan assets, PHI considers actual historical returns, economic forecasts and the judgment of its investment consultants on expected long-term performance for the types of investments held by the plan. The plan assets consist of equity and fixed income investments, and when viewed over a long time horizon, are expected to yield a return on assets of 8.75%.

Plan Assets

     Pepco Holdings' pension plan weighted-average asset allocations at December 31, 2004, and 2003, by asset category are as follows:

Asset Category	Plan Assets at December 31 2004      2003		Target Plan Asset Allocation	Minimum/ Maximum
Equity securities	66%	64%	60%	55% - 65%
Debt securities	33%	35%	35%	30% - 50%
Other	1%	1%	5%	0% - 10%
Total	100%	100%	100%

     In developing an asset allocation policy for its Retirement Plan, PHI examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, PHI examined the risk/return tradeoffs of alternative asset classes and asset mixes given long-term historical relationships, as well as prospective capital market returns. PHI also conducted an asset/liability study to match projected asset growth with projected liability growth and provide sufficient liquidity for projected benefit payments. By incorporating the results of these analyses with an assessment of its risk posture, and taking into account industry practices, PHI developed its asset mix guidelines. Under these guidelines, PHI diversifies assets in order to protect against large investment losses and to reduce the probability of excessive performance volatility while maximizing return at an acceptable risk level. Diversification of assets is impleme nted by allocating monies to various asset classes and investment styles within asset classes, and by retaining investment management firm(s) with complementary investment philosophies, styles and approaches. Based on the assessment of demographics, actuarial/funding, and business and financial characteristics, PHI believes that its risk posture is slightly below average relative to other pension plans. Consequently, Pepco Holdings believes that a slightly below average equity exposure (i.e., a target equity asset allocation of 60%) is appropriate for the Retirement Plan.

     On a periodic basis, Pepco Holdings reviews its asset mix and rebalances assets back to the target allocation over a reasonable period of time.

     No Pepco Holdings common stock is included in pension program assets.

Cash Flows

Contributions

     Pepco Holdings, Inc. funding policy with regard to the Retirement Plan is to maintain a funding level in excess of 100% with respect to its accumulated benefit obligation (ABO). PHI's Retirement Plan defined benefit plan currently meets the minimum funding requirements of ERISA without any additional funding. In 2004 and 2003, PHI made discretionary tax-deductible cash contributions to the plan of $10.0 million and $50.0 million, respectively, in line with its funding policy. Assuming no changes to the

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current pension plan assumptions, PHI projects no funding will be required under ERISA in 2005; however, PHI may elect to make a discretionary tax-deductible contribution, if required to maintain its plan assets in excess of its ABO.

Expected Benefit Payments

     The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid from the Retirement Plan:

Years	Pension       Benefits
2005	$ 89.4
2006	91.6
2007	102.0
2008	108.2
2009	113.4
2010-2014	619.7

Other Post-Retirement Benefits

     In addition to sponsoring non-contributory retirement plans, Pepco Holdings provides certain post-retirement health care and life insurance benefits for eligible retired employees. Certain groups of employees hired January 1, 2005 or later will not have company subsidized retiree medical coverage; however, they will be able to purchase coverage at full cost through the company. Pepco Holdings uses a December 31 measurement date for its plans.

     The acquisition of Conectiv by Pepco in August 2002 resulted in purchase accounting requirements that are reflected in the net periodic benefit cost. Under this accounting treatment, Conectiv's accrued post-retirement health care and life insurance liability was adjusted on August 1, 2002 through consolidation to recognize all previously unrecognized actuarial gains and losses, all unrecognized prior service costs, and the remainder of any unrecognized obligation or asset existing at the date of the initial application of SFAS No. 106. The Conectiv Plan transferred a projected benefit obligation of $320 million and plan assets of $100 million on August 1, 2002.

     During 2004, PHI announced amendments to its post-retirement health care plans for certain groups of eligible employees. The amendments included changes to coverage and retiree cost-sharing, and are reflected as a reduction in PHI's 2004 net periodic benefit cost and a reduction of $42 million in projected benefit obligation at December 31, 2004.

     Plan assets are stated at their market value as of the measurement date, December 31. All dollar amounts in the following tables are in millions of dollars.

     The following tables provide a roll forward of the changes in the benefit obligation and plan assets for the most recent two years: 

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	Other Post- Retirement Benefits
	2004	2003
Change in Benefit Obligation
Benefit obligation at beginning of year	$ 511.9	$ 472.4
Service cost	8.6	9.4
Interest cost	35.4	32.9
Amendments	(42.4)	-
Actuarial loss	117.0	31.0
Benefits paid	(37.0)	(33.8)
Benefit obligation at end of year	$ 593.5	$ 511.9
Change in Plan Assets
Fair value of plan assets at beginning of year	$ 145.2	$ 123.0
Actual return on plan assets	15.7	25.8
Company contributions	41.0	30.2
Benefits paid	(37.0)	(33.8)
Fair value of plan assets at end of year	$ 164.9	$ 145.2

     The following table provides a reconciliation of benefit obligations, plan assets and funded status of the plans:

	Other Post- Retirement Benefits
	2004	2003
Fair value of plan assets at end of year	$164.9	$145.2
Benefit obligation at end of year	593.5	511.9
Funded status (plan assets less than plan obligations)	(428.6)	(366.7)
Amounts not recognized:
Unrecognized net actuarial loss	188.5	89.0
Unrecognized initial net obligation	(29.5)	10.8
Net amount recognized	$(269.6)	$(266.9)

     The following table provides a reconciliation of the amounts recognized in PHI's Consolidated Balance Sheets as of December 31:

	Other Post- Retirement Benefits
	2004	2003
Prepaid benefit cost	$     -	$     -
Accrued benefit cost	(269.6)	(266.9)
Net amount recognized	$(269.6)	$(266.9)

     The table below provides the components of net periodic benefit costs recognized for the years ended December 31. A portion of the net periodic benefit cost is capitalized within PHI's Consolidated Balance Sheets.

Components of Net Periodic Benefit Cost
	Other Post- Retirement Benefits
	2004	2003	2002
Service cost	$ 8.6	$ 9.5	$ 7.2
Interest cost	35.4	32.9	20.0
Expected return on plan assets	(9.9)	(8.3)	(5.2)
Recognized actuarial loss	9.5	8.0	6.1
Net periodic benefit cost	$43.6	$42.1	$28.1

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     The 2004 net periodic benefit cost amount of $43.6 million, includes $10.5 million for ACE. The remaining net periodic benefit cost is related to other PHI subsidiaries. The 2003 net periodic benefit cost amount of $42.1 million, includes $10.0 million for ACE. The remaining net periodic benefit cost is related to other PHI subsidiaries. The 2002 net periodic benefit cost amount of $28.1 million includes $4.3 million for ACE. The remaining 2002 net periodic benefit cost is related to other PHI subsidiaries. ACE's annual net periodic benefit cost for 2002 was $9.5 million.

     The following weighted average assumptions were used to determine the benefit obligations at December 31:

Assumptions
Weighted-average assumptions used to determine benefit obligations at December 31
	Other Post- Retirement Benefits
	2004	2003
Discount rate	5.875%	6.25%
Rate of compensation increase	4.50%	4.50%

     The following weighted average assumptions were used to determine the net periodic benefit cost for years ended December 31:

Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31
	Other Post- Retirement Benefits
	2004	2003
Discount rate	6.25%	6.75%
Expected long-term return on plan assets	8.75%	8.75%
Rate of compensation increase	4.50%	4.50%

     In selecting an expected rate of return on plan assets, PHI considers actual historical returns, economic forecasts and the judgment of its investment consultants on expected long-term performance for the types of investments held by the plan. The plan assets consist of equity and fixed income investments, and when viewed over a long time horizon, are expected to yield a return on assets of 8.75%.

     The table below provides the assumed health care trend rates as of December 31:

Assumed health care cost trend rates at December 31
	2004	2003
Health care cost trend rate assumed for next year	9%	8%
Rate to which the cost trend rate is assumed to   decline (the ultimate trend rate)	5%	5%
Year that the rate reaches the ultimate trend rate	2009	2007

     Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1-Percentage- Point Increase	1-Percentage- Point Decrease
Effect on total of service and interest cost	$ 1.8	$ (1.7)
Effect on post-retirement benefit obligation	25.0	(23.0)

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Plan Assets

     Pepco Holdings' post-retirement plan weighted-average asset allocations at December 31, 2004, and 2003, by asset category are as follows:

	Plan Assets    at December 31,    2004         2003
Asset Category
Equity securities	65%	63%
Debt securities	35%	37%
Total	100%	100%

     No Pepco Holdings common stock is included in post-retirement program assets.

Cash Flows

Contributions

     ACE funded a portion of their estimated post-retirement liability through the use of an IRC 501 (C) (9) Voluntary Employee Beneficiary Association (VEBA). In 2004 and 2003, ACE contributed $9.3 million and $5.3 million, respectively, to the plans, and assuming no changes to the current pension plan assumptions, expects similar amounts to be contributed in 2005.

Expected Benefit Payments

     The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Years	Pension       Benefits
2005	$ 36.0
2006	36.3
2007	38.6
2008	40.6
2009	42.4
2010-2014	225.3

     FASB Staff Position (FSP 106-2), Accounting and Disclosure
       Requirements Related to the Medicare Prescription Drug, Improvement
       and Modernization Act of 2003

     The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) became effective on December 8, 2003. The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

     Pepco Holdings sponsors post-retirement health care plans that provide prescription drug benefits. Pepco Holdings did not elect the deferral of appropriate accounting permitted by the FASB Staff position (FSP) 106-1. The Accumulated Post-retirement Benefit Obligation (APBO) as of December 31, 2004 and December 31, 2003 has been reduced by $28 million to reflect the effects of the Act. This reduction includes both the decrease in the cost of future

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benefits being earned and an amortization of the APBO reduction over the future average working lifetime of the participants, or 12 years.The anticipated claims costs expected to be incurred have been adjusted to reflect the cost sharing between Medicare and Pepco Holdings. Participation rates have not been changed. In reflecting the effects of the Act, Pepco Holdings has determined which plans are eligible for Medicare cost sharing by analyzing the terms of each of its plans. It has recognized Medicare cost sharing for a plan only if Pepco Holdings' projected prescription drug coverage is expected to be at least as generous as the expected contribution by Medicare to a prescription drug plan not provided by Pepco Holdings.

     The effect of the subsidy on the 2004 other post-retirement net periodic benefit cost of $43.6 million is approximately a $3.6 million reduction due to the subsidy. Approximately $2.0 million is related to the amortization of the actuarial gain, and approximately $1.6 million is a subsidy-related reduction in interest cost on the APBO.

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(7)  LONG-TERM DEBT

     Long-term debt outstanding as of December 31, 2004 and 2003 is presented below.

Type of Debt	Interest Rates	Due	2004		2003
			(Dollars in Millions)
First Mortgage Bonds:
	6.18%-7.15%	2005-2008	$156.0	$165.0
	7.25%-7.63%	2010-2014	8.0	8.0
	6.63%	2013	68.6	68.6
	7.68%	2015-2016	17.0	17.0
	6.80%(a)	2021	38.9	38.9
	7.00%	2023	-	62.5
	5.60%(a)	2025	4.0	4.0
	6.15%-7.20%(a)	2028-2029	-	129.6
	Variable(a)	2029	54.7	-
	5.80%	2034	120.0	-
			467.2	493.6
Amortizing First Mortgage Bonds	6.38%	2004-2006	-	2.0
Medium-Term Notes (unsecured)	7.50%-7.52%	2007	15.0	15.0
Total long-term debt			482.2	510.6
Net unamortized discount			(.6)	(2.1)
Current portion (b)			(40.0)	(11.0)
Total net long-term debt			$441.6	$  497.5
Transition Bonds   ACE Funding:
	2.89%	2010	75.2	94.5
	2.89%	2011	39.4	46.0
	4.21%	2013	66.0	66.0
	4.46%	2016	52.0	52.0
	4.91%	2017	118.0	118.0
	5.05%	2020	54.0	54.0
	5.55%	2023	147.0	147.0
			551.6	577.5
Net unamortized discount			(.2)	(.3)
Current portion (b)			(28.1)	(25.9)
Total long-term transition bonds   issued by ACE Funding			$523.3	$551.3

(a)  First Mortgage Bonds issued as security for tax-exempt bonds and senior notes.

(b)  Included in short-term debt on the accompanying balance sheets.

     The outstanding First Mortgage Bonds issued by ACE are secured by a lien on substantially all of the issuing company's property, plant and equipment.

    The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond charges collected from ACE's customers are not available to creditors of ACE. The Transition Bonds are obligations of ACE Funding and are non-recourse to ACE.

     The debentures issued to the Financing Trust were redeemed during 2004 and totaled $25.8 million at December 31, 2003.

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     The aggregate principal amount of long-term debt including transition bonds outstanding at December 31, 2004, that will mature in each of 2005 through 2009 and thereafter is as follows: 2005-$68.1 million; 2006-$94.0 million; 2007-$45.9 million; 2008-$80.9 million; 2009-$32.2 million; and thereafter $712.7 million.

SHORT-TERM DEBT

     ACE, a regulated utility has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. A detail of the components of ACE's short-term debt at December 31, 2004 and 2003 is as follows.

	2004	2003
	(Millions of Dollars)
Commercial paper	$ 32.7	$   -
Variable rate demand bonds	22.6	22.6
Current portion of long-term debt	68.1	36.9
Total	$123.4	$59.5

Commercial Paper

     ACE maintains an ongoing commercial paper program of up to $250 million. The commercial paper notes can be issued with maturities up to 270 days from the date of issue. The commercial paper program is backed by $500 million in credit facilities, shared with Pepco and DPL. ACE's credit limit under the facilities is the lower of $300 million and the maximum amount of short-term debt authorized by the applicable regulatory authority, except that the aggregate amount of credit utilized by Pepco, DPL and ACE at any given time under these facilities may not exceed $500 million.

     ACE had $32.7 million of commercial paper outstanding at December 31, 2004 and none outstanding at December 31, 2003. Interest rates for commercial paper issued during 2004 ranged from 1.07% to 2.63%. Interest rates for commercial paper issued during 2003 ranged from 1.00% to 1.25%. Maturities were less than 270 days for all commercial paper issued.

Variable Rate Demand Bonds

     Variable Rate Demand Bonds ("VRDB") are included in short-term debt because the VRDB are due on demand by the bondholder. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. ACE expects the bonds submitted for purchase will continue to be remarketed successfully due to its credit worthiness and the bonds' interest rates being set at market rates. ACE may also utilize one of the fixed rate/fixed term conversion options of the bonds. Thus, ACE considers the VRDB to be a source of long-term financing. The VRDB outstanding in 2004 and 2003 mature in 2014 ($18.2 million) and 2017 ($4.4 million). Interest rates ranged from .82% to 1.98% in 2004 and .65% to 1.30% in 2003.

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Credit Facility Agreements

     In July 2004, Pepco Holdings, Pepco, DPL and ACE entered into a five-year credit agreement with an aggregate borrowing limit of $650 million. This agreement replaced a $550 million 364-day credit agreement that was entered into on July 29, 2003. The respective companies also are parties to a three-year credit agreement that was entered into in July 2003 and terminates in July 2006 with an aggregate borrowing limit of $550 million. Pepco Holdings' credit limit under these facilities is $700 million, and the credit limit of each of Pepco, DPL and ACE under these facilities is the lower of $300 million and the maximum amount of short-term debt authorized by the appropriate state commission, except that the aggregate amount of credit utilized by Pepco, DPL and ACE at any given time under these facilities may not exceed $500 million. Funds borrowed under these facilities are available for general corporate purposes. Either credit facility also can be used as credit support for the commercial paper programs of the respective companies. The three-year and five-year credit agreements contain customary financial and other covenants that, if not satisfied, could result in the acceleration of repayment obligations under the agreements or restrict the ability of the companies to borrow under the agreements. Among these covenants is 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 agreements. As of December 31, 2004, the applicable ratios for Pepco Holdings, Pepco, DPL and ACE were 59.0%, 58.5%, 52.1% and 50.2%, respectively. The credit agreements also contain a number of customary events of default that could result in the acceleration of repayment obligations under the agreements, including (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 agreements) of Pepco Holdings or the failure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE.

(8)  INCOME TAXES

     ACE, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to ACE pursuant to a written tax sharing agreement which was approved by the SEC as part of Pepco's acquisition of Conectiv on August 1, 2002. Under this tax sharing agreement, PHI's consolidated federal income tax liability is allocated based upon PHI's and its subsidiaries' separate taxable income or loss, with the exception of the tax benefits applicable to non-acquisition debt expenses of PHI. Such tax benefits are allocated to subsidiaries with taxable income.

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     The provision for income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred tax liabilities (assets) are shown below.

Components of Consolidated Income Tax Expense
	2004	2003	2002
	(Dollars in Millions)
Federal:  Current	$60.9	$ 20.1	$(39.6)
Deferred	(25.1)	1.9	52.0
State:    Current	4.5	12.7	11.4
Deferred	6.7	(5.4)	(5.5)
Investment tax credit adjustments, net(1)	(4.7)	(2.0)	(2.0)
Total Income Tax Expense	42.3	27.3	16.3
Extraordinary item	-	4.1	-
Total Income Tax Expense	$42.3	$31.4	$16.3

(1) Includes $2.7 million of deferred investment tax credits reversed and credited to tax expense due to the prior sales of generating plants that occurred in 2001.

Reconciliation of Effective Income Tax Rate
	For the Year Ended December 31,
	2004		2003		2002
	Amount	Rate	Amount	Rate	Amount	Rate
	(Amounts in Millions)
Statutory federal    income tax expense	$37.4	35%	$24.1	35%	$15.6	35%
State income taxes,    net of federal    benefit	7.3	7	4.7	7	3.8	9
Plant basis differences	2.0	2	-	-	1.0	2
Investment tax credit    amortization	(4.7)	(4)	(2.0)	(3)	(2.0)	(4)
Prior period income taxes	1.0	1	-	-	-	-
Other, net	(.7)	(1)	.5	1	(2.1)	(5)
Total	42.3	40%	27.3	40%	16.3	37%
Extraordinary item	-		4.1		-
Total	$42.3	40%	$31.4	40%	$16.3	37%

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Components of Deferred Income Taxes

     The tax effects of temporary differences that give rise to ACE's net deferred tax liability are shown below.

			2004		2003
	(Dollars in Millions)
Deferred tax liabilities:
Utility plant basis differences		$	430.6	$	418.5
Deferred recoverable income taxes			4.7		5.8
Payment for termination of purchased power   contracts with non-utility electric generators			82.1		86.7
Deferred electric service expenses			29.8		61.2
Other			17.3		16.9
Total deferred tax liabilities			564.5		589.1
Deferred tax assets:
Deferred investment tax credits			9.8		13.2
Other			58.7		61.2
Total deferred tax assets			68.5		74.4
Total deferred taxes, net		$	496.0	$	514.7

     At December 31, 2004, ACE had unused state net operating loss carryforwards of $84.0 million, which will expire in 2010. Since ACE expects to fully utilize this amount, no valuation allowance is necessary.

Taxes Other Than Income Taxes

     Taxes, other than income taxes, charged to operating expense for each period are shown below.

	2004	2003	2002
Gross Receipts/Delivery	$18.4	$20.6	$22.2
Property	2.4	2.2	2.5
Environmental, Use and Other	(.7)	1.0	.1
Total	$20.1	$23.8	$24.8

(9)  PREFERRED STOCK

     The preferred stock amounts outstanding as of December 31, 2004 and 2003 are as follows:

		Shares Outstanding			December 31,
Series	Redemption Price	2004	2003		2004	2003
				(Dollars in Millions)
Serial Preferred Stock
$100 per share par value
4.00%-5.00%	$100.00-$105.50	62,305	62,305		$6.2	$6.2

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(10)FAIR VALUE OF FINANCIAL INSTRUMENTS

     The estimated fair values of ACE's financial instruments at December 31, 2004 and 2003 are shown below.

	2004		2003
	Carry Amount	Fair Value	Carrying Amount	Fair Value
	(Dollars in Millions)
Debentures issued to Financing Trust	$    -	$    -	$ 25.8	$ 25.8
Long-term debt	$441.6	$463.7	$497.5	$544.6
Redeemable Serial Preferred Stock	$  6.2	$  4.3	$  6.2	$  3.6
Transition Bonds issued by ACE Funding	$523.3	$537.5	$551.3	$583.1

     The methods and assumptions below were used to estimate, at December 31, 2004 and 2003, the fair value of each class of financial instruments shown above for which it is practicable to estimate that value.

     The fair value of the Investments was derived based on quoted market prices.

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

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

     The carrying amounts of all other financial instruments in ACE's accompanying financial statements approximate fair value.

(11) LONG-TERM PURCHASED POWER CONTRACTS

     As of December 31, 2004, ACE's commitments under long-term purchased power contracts provided ACE 500 megawatts of capacity and varying amounts of firm electricity per hour during each month of a given year. Commitments for purchased capacity under contracts decreased by approximately 200 megawatts in 2004, primarily due to the replacement of the capacity supplied by these contracts with the capacity and energy to be provided by the BGS suppliers that were selected by the NJBPU required auction sale of BGS load. Based on existing contracts as of December 31, 2004, the commitments of ACE during the next five years for capacity and energy under long-term purchased power contracts are estimated to be as follows: $261.7 million in 2005, $255.6 million in 2006, $257.1 million in 2007, $256.6 million in 2008, and $258.4 million in 2009.

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(12)COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Rate Proceedings

     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. The petition was based on actual data for the nine months ended September 30, 2002, and forecasted data for the three months ended December 31, 2002 and sought an overall rate increase of approximately $68.4 million, consisting of an approximately $63.4 million increase in electricity distribution rates and $5 million for recovery of regulatory assets through the RARC. In October 2003, ACE filed an update supporting an overall rate increase of approximately $41.3 million, consisting of a $36.8 million increase in electricity distribution rates and a RARC of $4.5 million. This petition was ACE's first increase request for electric distribution rates since 1991. The requested increase would apply to all rate schedules in ACE's tariff. The Ratepayer Advocate filed testimony on January  3, 2004, proposing an annual rate decrease of $11.7 million. Intervenor groups representing industrial users and local generators filed testimony that did not take a position with respect to an overall rate change but their proposals, if implemented, would affect the way in which an overall rate increase or decrease would be applied to the particular rates under which they receive service. ACE's rebuttal testimony, filed in February 2004, made some changes to its October filing and proposed an overall rate increase of approximately $35.1 million, consisting of a $30.6 million increase in distribution rates and a $4.5 million increase in the RARC. Hearings were held before an Administrative Law Judge in late March, early April and May 2004. At the hearing held in April 2004, the Ratepayer Advocate proposed an annual rate decrease of $4.5 million, modifying its earlier proposal that rates be decreased by $11.7 million annually. The Ratepayer Advocate and Staff of the NJBPU filed their briefs in this proceeding in August 2004. The Ratepayer Advocate's brief supported its earlier proposal of an annual rate decrease of $4.5 million. The Staff's brief, however, stated for the first time its position calling for an overall decrease of $10.8 million. Reply briefs were filed on August 23, 2004. Settlement discussions between ACE, the NJBPU Staff and the Ratepayer Advocate have been ongoing.

     On December 12, 2003, the NJBPU issued an order also consolidating outstanding issues from several other proceedings into the base rate case proceeding. On December 22, 2003, ACE filed a Motion for Reconsideration in which it suggested that these issues be dealt with in a Phase II to the base rate case to address the outstanding issues identified in the December 12, 2003 Order. After discussion with the parties to the base rate case, it was agreed that a Phase II to the base rate case to address these issues, along with the $25.4 million of deferred restructuring costs previously transferred into the base rate case, would be initiated in April 2004. On April 15, 2004, ACE filed testimony with the NJBPU initiating a Phase II to the base rate proceeding described above. The parties to this case have been actively engaged in settlement discussions in conjunction with settlement of Phase I issues.

     On August 31, 2004, ACE filed requests with the NJBPU proposing changes to its Transition Bond Charge, its Market Transition Charge - Tax rate, and its BGS Reconciliation charges. The net impact of these rate changes is to decrease ACE's annual revenues by approximately 1.5%. All of these rate changes were implemented on October 1, 2004.

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Restructuring Deferral

     Pursuant to a July 1999 summary order issued by the NJBPU under the New Jersey Electric Discount and Energy Competition Act (EDECA) (which was subsequently affirmed by a final decision and order issued in March 2001), ACE was obligated to provide basic generation service (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 Ener gy Adjustment Clause and ACE's Demand Side Management Programs. ACE established a regulatory asset in an amount equal to the balance.

     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.

     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) transferred to ACE's 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 disallowa nces. ACE believes the record does not justify the level of disallowance imposed by the NJBPU. In August 2004, ACE filed with the Appellate Division of the Superior Court of New Jersey, which hears appeals of New Jersey administrative agencies, including the NJBPU, a Notice of Appeal related to the July 2004 final order. ACE cannot predict the outcome of this appeal.

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

     Pursuant to a September 25, 2003 NJBPU order, ACE filed a report on April 30, 2004 with the NJBPU recommending that the B.L. England generating facility be shut down in accordance with the terms of an April 26, 2004 preliminary settlement agreement among PHI, Conectiv and ACE, the New Jersey Department of Environmental Protection (NJDEP) and the Attorney General of New Jersey. The report stated that the operation of the B.L. England facility is necessary at the present time to satisfy reliability standards,

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but that those reliability standards could also be satisfied in other ways. The report concludes 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 lines into southern New Jersey. ACE cannot predict whether the NJBPU will approve the construction of the additional transmission lines.

     In letters dated May and September 2004 to PJM Interconnection, LLC (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 the transmission upgrades necessary to maintain reliability in the Atlantic zone after the retirement of B.L. England. 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 A CE 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 FERC and the state regulatory commissions and, therefore, cannot predict the financial impact to ACE of installing the recommended transmission upgrades. However, in the event that the NJBPU makes satisfactory findings and grants other requested approvals concerning the retirement of B.L. England and approves the construction of the transmission upgrades required to maintain reliability in the Atlantic zone after such retirement, 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.

     On November 1, 2004, ACE made a filing with the NJBPU requesting approval of the transmission upgrades required to maintain reliability in the Atlantic zone after the retirement of B.L. England. On December 22, 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 cannot predict the outcome of these two proceedings.

     On November 12, 2004, ACE made a filing with the NJBPU requesting approval of year 2005 capital projects with respect to B.L. England. This filing was made pursuant the September 25, 2003 B.L. England rate order, which established a requirement that ACE file for approval of capital expenditures in excess of $1 million. For 2005, four projects, totaling $3.2 million in capital expenditures, have been identified as necessary to allow continued operation of B.L. England until its retirement. Two of these projects are well below the $1 million threshold set forth in the

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September 25, 2003 NJBPU order and two are above that threshold. ACE cannot predict the outcome of this proceeding.

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.

     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

     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:

· 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,

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	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 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. Englandgenerating 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.
·	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 necessary to satisfy the EPA's new cooling water intake structure regulations in accordance with a schedule that NJDEP will establish in the renewal New Jersey Pollutant Discharge Elimination System (NJPDES) permit for the B.L. England facility. The schedule will take 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.

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     The preliminary settlement agreement also 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.

Contractual Obligations

     As of December 31, 2004, ACE contractual obligations under power purchase agreements with non-utility generators were $261.7 million in 2005, $512.7 million in 2006 to 2007 and $514.9 million in 2008 to 2009.

(13)  RELATED PARTY TRANSACTIONS

     PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including ACE. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries' share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated in consolidation and no profit results from these transactions. PHI Service Company costs directly charged or allocated to ACE for the years ended December 31, 2004, 2003 and 2002 were $85.3 million, $89.5 million and $92.6 million, respectively.

     In addition to the PHI Service Company charges described above, ACE's financial statements include the following related party transactions in its Consolidated Statement of Earnings:

	For the Year Ended December 31,
	2004	2003	2002
	(In Millions)
Purchased power from Conectiv Energy Supply	$(41.6)	$  -	$  -
Tolling arrangement with   Conectiv Energy Supply	-	7.2	-
Meter reading services provided by   Millennium Account Services LLC	(3.7)	(3.5)	(3.3)
Inter-company lease transactions   related to computer services	1.7	1.9	2.1
Inter-company lease transactions   related to facilities	(1.9)	(1.8)	(1.8)
Money pool interest income	.5	1.0	.3

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     As of December 31, 2004 and 2003, ACE had the following material balances due to and from related parties:

	2004	2003
	(In Millions)
Receivable from Related Party
King Street Assurance	$  2.6	$  2.6
Payable to Related Party (current)
PHI Service Company	(10.3)	(14.7)
Conectiv Energy Supply	(4.5)	.4
Money Pool Balance with Pepco Holdings	$  1.7	$103.0

(14)2003 EXTRAORDINARY ITEM

     In July 2003, the New Jersey Board of Public Utilities (NJBPU) approved the determination of stranded costs related to ACE's January 31, 2003, petition relating to its B.L. England generating facility. The NJBPU approved recovery of $149.5 million. As a result of the order, ACE reversed $10.0 million of accruals for the possible disallowances related to these stranded costs. The credit to income of $5.9 million is classified as an extraordinary gain in ACE's 2003 financial statements, since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.

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(15)QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

     The quarterly data presented below reflect all adjustments necessary in the opinion of management for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations, differences between summer and winter rates, and the scheduled downtime and maintenance of electric generating units.

	2004
	First Quarter	SecondQuarter	Third  Quarter	Fourth  Quarter	Total
	(Dollars in Millions)
Total Operating Revenue	$322.4	$315.9	$420.6	$274.3	$1,333.2
Total Operating Expenses	298.3	257.2 (a)	363.4	255.0	1,173.9
Operating Income	24.1	58.7	57.2	19.3	159.3
Other Expenses	(12.5)	(13.9)	(12.9)	(13.1)	(52.4)
Income Before Income Tax Expense	11.6	44.8	44.3	6.2	106.9
Income Taxes	4.8	18.4	18.7	.4	42.3
Net Income	6.8	26.4	25.6	5.8	64.6
Dividends on Preferred Stock	.1	.1	.1	-	.3
Earnings Available for   Common Stock	$  6.7	$ 26.3	$ 25.5	$  5.8	$   64.3

	2003
	First Quarter	Second    Quarter	Third  Quarter	Fourth  Quarter	Total
	(Dollars in Millions)
Total Operating Revenue	$301.2	$256.5	$410.8	$267.5	$1,236.0
Total Operating Expenses	275.6	244.0	351.1	245.2	1,116.0
Operating Income	25.6	12.5	59.7	22.3	120.0
Other Expenses	(11.0)	(10.5)	(14.3)	(13.6)	(49.4)
Distributions on Preferred   Securities of Subsidiary Trust	1.4	.5	-	-	1.8
Income Before Income Tax Expense	13.2	1.5	45.4	8.7	68.8
Income Taxes	5.1	.3	18.4	3.5	27.3
Income Before Extraordinary Item	8.1	1.2	27.0	5.2	41.5
Extraordinary Item	-	5.9(c)	-	-	5.9
Net Income	8.1	7.1(b)	27.0	5.2	47.4
Dividends on Preferred Stock	.1	.1	.1	-	.3
Earnings Available for   Common Stock	$  8.0	$  7.0	$ 26.9	$  5.1	$   47.1

NOTE:	Sales of electric energy are seasonal and, accordingly, comparisons by quarter within a year are not meaningful.
(a)	Includes a $14.7 million pre-tax ($8.6 million after-tax) gain from the condemnation settlement associated with the transfer of Vineland distribution assets.
(b)	Includes a charge of $27.5 million pre-tax ($16.3 million after-tax) related to ACE's New Jersey deferral disallowance.
(c)	Represents the favorable impact related to ACE's accrual reversal.

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Item 9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
              FINANCIAL DISCLOSURE

     None for all registrants.

Item 9A.    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 December 31, 2004, 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 accounting officer, as appropriate to allow timely decision s regarding required disclosure.

Management's Report on Internal Control Over Financial Reporting

     See "Management's Report on Internal Control Over Financial Reporting" in Part II, Item 8 on page 154 of this Form 10-K.

Attestation Report of the Registered Public Accounting Firm

     See "Report of Independent Registered Public Accounting Firm" in Part II, Item 8 on page 155 of this Form 10-K.

Changes in Internal Control Over Financial Reporting

     During the quarter ended December 31, 2004, 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 December 31, 2004, 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

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specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief accounting officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

     During the quarter ended December 31, 2004, 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.

Delmarva Power and 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 December 31, 2004, 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 accounting officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

     During the quarter ended December 31, 2004, 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 December 31, 2004, 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 accounting officer, as appropriate to allow timely decisions regarding required disclosure.

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Changes in Internal Control Over Financial Reporting

     During the quarter ended December 31, 2004, 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.

Item 9B.  OTHER INFORMATION

Pepco Holdings, Inc.

     The following table sets forth for each Named Executive Officer of Pepco Holdings, Inc. ("PHI") (which officers were determined by reference to SEC Regulation S-K, Item 402(a)(3) based on 2003 compensation, or in the cases of Messrs. Rigby and Spence, 2004 compensation) information concerning determinations made with respect to the compensation paid or payable for services in all capacities to PHI and its subsidiaries consisting of (i) the establishment of base salary for 2005, (ii) the determination of the annual bonus for 2004, and (iii) the determination of the long-term incentive plan payout for the performance cycle ending in 2004.

Name	Title	2005 Base Salary	2004 Annual Bonus (1)	2005 Incentive Plan Payouts (2)
Dennis R. Wraase	Chairman, President   and Chief Executive   Officer	$825,000	$438,588	$197,069
William T. Torgerson	Vice Chairman and   General Counsel	$492,000	$237,737	$135,312
Thomas S. Shaw	Executive Vice   President	$488,000	$237,237	$164,613
Joseph M. Rigby	Senior Vice President   and Chief Financial   Officer	$350,000	$119,786	$  72,088
Andrew W. Williams	Senior Vice President   and Chief Risk   Officer	$340,000	$132,132	$115,962
William H. Spence	Senior Vice President	$285,000	$171,013	$72,088
John M. Derrick, Jr.	(3)	(3)	$201,451	$396,182

(1)	Consists of awards under the Annual Executive Incentive Compensation Plan based on the extent to which the following pre-established criteria were satisfied: (1) earnings relative to the corporate plan, (2) cost containment and (3) electric system reliability.
(2)	In 2002, PHI granted performance award opportunities under PHI's Merger Integration Success Program, a component of PHI's Long-Term Incentive Plan pursuant to which the recipient was entitled to earn some or all of the maximum award of shares of PHI's common stock, par value $.01 per share (the "Common Stock"), based on PHI's performance and the extent to which operating efficiencies and expense reduction goals were attained through December 31, 2004. On March 11, 2005, the PHI Compensation/Human Resources Committee approved the vesting of the awards. The value of the vested Common Stock has been calculated by multiplying the number of vested shares by the market price of the Common Stock on the day preceding the vesting date.
(3)	Retired June 1, 2004.

Long-Term Incentive Plan

     Certain executives of PHI, including, Messrs. Wraase, Torgerson, Shaw, Rigby, Williams and Spence, are eligible to participate in the PHI Long-Term Incentive Plan ("LTIP").  Based on a recent Securities and Exchange Commission staff interpretation suggesting that the receipt of a performance-based incentive award may constitute the entry into a "material definitive agreement" that requires the filing of a Form 8-K, PHI is disclosing that on January 26, 2005, the PHI Compensation/Human Resources Committee granted restricted stock awards under the Performance Restricted Stock Program (the

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"Program") established under PHI's LTIP.  In accordance with the Program, participating executives, including the executives named above, are entitled to earn shares of PHI's common stock, $.01 par value (the "Common Stock") to the extent the pre-established performance objective is met for the specified performance period, in this case from January 1, 2005 through December 31, 2007.

     The performance objective for the 2005 to 2007 performance period is based on the Company's total shareholder return compared to other companies in a peer group comprised of 20 gas and electric distribution companies. A participant is eligible to earn a number of shares of Common Stock ranging from 0% to 200% of the target performance award to the extent that the performance objective is achieved. The performance objective was fixed at the time the awards are made; however, if during the course of the performance period, a significant event occurs, as determined in the sole discretion of the PHI Compensation/Human Resources Committee, which the Committee expects to have a substantial effect on total shareholder performance during the period, the Committee may revise the targeted performance objective.   The shares of Common Stock earned by a participant will be fully vested on the date the performance award is earned.

     For further information regarding executive compensation, see Item 11 -- Executive Compensation, herein.

Potomac Electric Power Company

     The following table sets forth for each Named Executive Officer of Potomac Electric Power Company ("Pepco") (which officers were determined by reference to SEC Regulation S-K, Item 402(a)(3) based on 2003 compensation, or in the case of Mr. Rigby, 2004 compensation) information concerning determinations made with respect to the compensation paid or payable for services in all capacities to PHI and its subsidiaries, including Pepco, consisting of (i) the establishment of base salary for 2005, (ii) the determination of the annual bonus for 2004, and (iii) the determination of the long-term incentive plan payout for the performance cycle ending in 2004.

Name	Title	2005 Base Salary	2004 Annual Bonus (1)	2005 Incentive Plan Payouts (2)
Dennis R. Wraase	Chairman and Chief   Executive Officer	$825,000	$438,588	$197,069
Joseph M. Rigby	Senior Vice President   and Chief Financial   Officer	$350,000	$119,786	$ 72,088
Andrew W. Williams	Senior Vice President	$340,000	$132,132	$115,962
William J. Sim	President and Chief   Operating Officer	$270,000	$113,411	$ 76,353
Kirk J. Emge	General Counsel	$242,000	$ 70,574	$ 33,500
John M. Derrick, Jr.	(3)	(3)	$201,451	$396,182

(1)	Consists of awards under the PHI Annual Executive Incentive Compensation Plan based on the extent to which the following pre-established criteria were satisfied: (1) earnings relative to the corporate plan, (2) cost containment and (3) electric system reliability.
(2)	In 2002, PHI granted performance award opportunities under PHI's Merger Integration Success Program, a component of PHI's Long-Term Incentive Plan pursuant to which the recipient was entitled to earn some or all of the maximum award of shares of PHI's common stock, par value $.01 per share (the "Common Stock"), based on PHI's performance and the extent to which operating efficiencies and expense reduction goals were attained through December 31, 2004. On March 11, 2005, the PHI Compensation/Human Resources Committee approved the vesting of the awards. The value of the vested Common Stock has been calculated by multiplying the number of vested shares by the market price of the Common Stock on the day preceding the vesting date.
(3)	Retired June 1, 2004.

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Long-Term Incentive Plan

     Certain executives of Pepco, including, Messrs. Wraase, Rigby, Williams, Sim and Emge, are eligible to participate in the PHI Long-Term Incentive Plan ("LTIP"). Based on a recent Securities and Exchange Commission staff interpretation suggesting that the receipt of a performance-based incentive award may constitute the entry into a "material definitive agreement" that requires the filing of a Form 8-K, PHI is disclosing that on January 26, 2005, the PHI Compensation/Human Resources Committee granted restricted stock awards under the Performance Restricted Stock Program (the "Program") established under PHI's LTIP.  In accordance with the Program, participating executives, including the executives named above, are entitled to earn shares of PHI's common stock, $.01 par value (the "Common Stock") to the extent the pre-established performance objective is met for the specified performance period, in this case from January 1, 2005 through Dec ember 31, 2007.

     The performance objective for the 2005 to 2007 performance period is based on the Company's total shareholder return compared to other companies in a peer group comprised of 20 gas and electric distribution companies. A participant is eligible to earn a number of shares of Common Stock ranging from 0% to 200% of the target performance award to the extent that the performance objective is achieved. The performance objective was fixed at the time the awards are made; however, if during the course of the performance period, a significant event occurs, as determined in the sole discretion of the PHI Compensation/Human Resources Committee, which the PHI Compensation/Human Resources Committee expects to have a substantial effect on total shareholder performance during the period, the PHI Compensation/Human Resources Committee may revise the targeted performance objective.    The shares of Common Stock earned by a participant will be fu lly vested on the date the performance award is earned.

     For further information regarding executive compensation, see Item 11 -- Executive Compensation, herein.

Delmarva Power & Light Company

     None

Atlantic City Electric Company

     None

Part III

Item 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Pepco Holdings, Inc.

     The information required by this Item 10 with regard to PHI, with the exception of the information set forth under the heading "Executive Officers of PHI and Pepco," is incorporated by reference to PHI's definitive proxy statement for the 2005 Annual Meeting of Shareholders to be filed with the Securities and Exchange Commission on or about March 31, 2005.

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Executive Officers of PHI and Pepco

     The names of the executive officers of Pepco Holdings and Pepco and their ages and the positions they held as of March 15, 2005 are set forth in the following table. Their business experience during the past five years is set forth in the footnotes to the following table.

PEPCO HOLDINGS
Name	Age	Office and Length of Service
Dennis R. Wraase	61	Chairman of the Board, President and CEO 5/04 - Present (1)
William T. Torgerson	60	Vice Chairman and General Counsel 6/03 - Present (2)
Thomas S. Shaw	57	Executive Vice President 8/02 - Present (3)
Joseph M. Rigby	48	Senior Vice President and CFO 5/04 - Present (4)
Andrew W. Williams	55	Senior Vice President and CRO 5/04 - Present (5)
Ed R. Mayberry	57	Senior Vice President 8/02 - Present (6)
Beverly L. Perry	57	Senior Vice President 10/02 - Present (7)
William J. Sim	60	Senior Vice President 8/02 - Present (8)
William H. Spence	48	Senior Vice President 8/02 - Present (9)
James P. Lavin	57	Vice President and Controller 8/02 - Present (10)
PEPCO
Name	Age	Office and Length of Service
Dennis R. Wraase	61	Chairman and CEO 5/04 - Present (1)
William J. Sim	60	President and COO 8/02 - Present (8)
Joseph M. Rigby	48	Senior Vice President and CFO 5/04 - Present (4)
Andrew W. Williams	55	Senior Vice President 1/01 - Present (5)
James P. Lavin	57	Vice President and Controller 8/02 - Present (10)
Anthony J. Kamerick	57	Vice President and Treasurer 4/94 - Present (11)
Kirk J. Emge	55	General Counsel 8/02 - Present (12)

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(1)	Mr. Wraase was President and Chief Operating Officer of PHI from August 2002 until June 2003 and President and Treasurer from February 2001 until August 2002. Mr. Wraase has been Chief Executive Officer of Pepco since August 2002. He was President and Chief Operating Officer of Pepco from January 2001 until August 2002, President and Chief Financial Officer from May 2000 until December 2000, and Executive Vice President and Chief Financial Officer from April 1999 until May 2000.
(2)	Mr. Torgerson was Executive Vice President and General Counsel of PHI from August 2002 until June 2003 and Secretary from February 2001 until August 2002. Mr. Torgerson served as Executive Vice President and General Counsel of Pepco from January 2001 until August 2002 and from April 1994 to December 2000 as Senior Vice President and General Counsel of Pepco.
(3)	Mr. Shaw has served as President and Chief Operating Officer of Conectiv since September 2000. From March 1998 to September 2000 he served as Executive Vice President of Conectiv.
(4)	Mr. Rigby served as President from July 2001 until May 2004 and as Chief Executive Officer of ACE from August 2002 until May 2004. He served as President of DPL from August 2002 until May 2004 and has served as Senior Vice President of Conectiv since September 2000. From July 1998 to September 2000, he served as Vice President of Conectiv.
(5)	Mr. Williams served as Senior Vice President and Chief Financial Officer of Pepco from January 2001 until May 2004. He was Group Vice President from April 1997 until December 2000.
(6)	Dr. Mayberry has served as President and Chief Executive Officer of Pepco Energy Services since May 1995.
(7)	Ms. Perry served as Vice President of Pepco from April 1999 to August 2002.
(8)	Mr. Sim has served as President and Chief Operating Officer of Pepco since August 2002 and was Senior Vice President of Pepco from January 2001 until August 2002 and Group Vice President from April 1997 until December 2000.
(9)	Mr. Spence has served as President and Chief Operating Officer, Conectiv Energy since August 2002 and as Senior Vice President of Conectiv since September 2000. From July 1998 to September 2000, he served as Vice President and General Manager, Conectiv.
(10)	Mr. Lavin has served as Vice President and Controller of Conectiv and Pepco since August 2002, Controller of ACE since March 1998, Vice President since August 2002 and Controller of DPL since March 1998, and Chief Financial Officer of ACE Funding since August 2002. From March 1998 until August 2002, he was Controller of Conectiv.
(11)	Mr. Kamerick served as Comptroller of Pepco from January 2002 until August 2002. He has also served as Vice President and Treasurer of Pepco Holdings since August 1, 2002.
(12)	Mr. Emge was Vice President of Pepco from April 1994 until August 2002. He has also served as Vice President of Pepco Holdings since August 2002.

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     Each PHI executive officer serves until the next succeeding Annual Meeting, and until their successors have been elected and qualified. The current term of office of each Pepco executive officer is from May 21, 2004, until the next succeeding Annual Meeting, and until their successors have been elected and qualified.

Potomac Electric Power Company

     The names of each of the directors of Pepco, their term of office and the length of service as a director of Pepco is set forth below.

· Joseph M. Rigby - Mr. Rigby has been a director of Pepco since May 21, 2004. His current term as director is from May 21, 2004, until the next succeeding Annual Meeting, and until his successor has been elected and qualified.

· Thomas S. Shaw - Mr. Shaw has been a director of Pepco since August 1, 2002. His current term as director is from May 21, 2004, until the next succeeding Annual Meeting, and until his successor has been elected and qualified.

· William J. Sim - Mr. Sim has been a director of Pepco since August 1, 2002. His current term as director is from May 21, 2004, until the next succeeding Annual Meeting, and until his successor has been elected and qualified. Mr. Sim is also a director of Williams Industries Inc.

· William T. Torgerson - Mr. Torgerson has been a director of Pepco since August 1, 2002. His current term as director is from May 21, 2004, until the next succeeding Annual Meeting, and until his successor has been elected and qualified.

· Andrew W. Williams - Mr. Williams has been a director of Pepco since August 1, 2002. His current term as director is from May 21, 2004, until the next succeeding Annual Meeting, and until his successor has been elected and qualified.

· Dennis R. Wraase - Mr. Wraase is Chairman of the Board of Pepco, a position he has held since May 21, 2004. He has been a director of Pepco since 1998. His current term as director is from May 21, 2004, until the next succeeding Annual Meeting, and until his successor has been elected and qualified.

     The age of each of the directors of Pepco as of March 15, 2005 and a description of the business experience of each of the directors of Pepco during the past five years, including each director's principal occupation and employment with PHI or its subsidiaries, and the identification of any other public company directorships held is presented under the heading "Executive Officers of PHI and Pepco" above.

      Pepco does not, nor is it required to, have an audit committee and, correspondingly, has no "audit committee financial expert" as that term is defined under Item 401(h) of SEC Regulation S-K. Pepco is not a listed issuer as defined by Section 10A-3 of the Exchange Act and, accordingly, is not subject to the disclosure requirements of Item 401(i) of SEC Regulation S-K.

     No director or executive officer of PHI or Pepco has a "family relationship" within the meaning of Item 401(d) of SEC Regulation S-K, with any other director or executive officer of PHI or Pepco.

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

Section 16(a) Beneficial Ownership Reporting Compliance

     Section 16(a) of the Exchange Act requires that each of Pepco's directors and executive officers, and any beneficial owner of more than 10% of Pepco's common stock, file with the SEC initial reports of beneficial ownership, and reports of changes in beneficial ownership, of Pepco's common stock. Such persons also are required by SEC regulations to furnish Pepco with copies of such reports. To Pepco's knowledge, based solely on its review of the copies of such reports furnished to Pepco and on the written representations made by such persons that no other reports were required, during the year ended December 31, 2004, no such director, executive officer or 10% beneficial owner failed to file on a timely basis the reports required by Section 16(a).

     Pepco Holdings has adopted a code of ethics that applies to Pepco's principal executive officer, principal financial officer, principal accounting officer and other senior financial officers (which is encompassed within Pepco Holdings' Code of Business Conduct and Ethics). Any amendment to, or waiver of, any provision of the Code of Business Conduct and Ethics applicable to Pepco's principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions will be promptly disclosed to shareholders through the filing of a Form 8-K with the Securities and Exchange Commission.

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

Item 11.EXECUTIVE COMPENSATION

Pepco Holdings, Inc.

     The information required by this Item 11 with regard to PHI is incorporated herein by reference to the information contained under the caption "Executive Compensation" in its definitive Proxy Statement for the 2005 Annual Meeting of Shareholders to be filed with the Securities and Exchange Commission on or about March 31, 2005.

Potomac Electric Power Company

     The following table sets forth compensation information for each of the last three fiscal years ended December 31, for the Chief Executive Officer and the four other most highly compensated executive officers of Pepco determined on the basis of aggregate salary and bonus for the year ended December 31, 2004(collectively, the "Pepco Named Executive Officers"). The information presented in the table from and after August 1, 2002 reflects compensation paid by PHI or its subsidiaries, and for periods prior to August 1, 2002 reflects compensation paid by Pepco or Conectiv.

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SUMMARY COMPENSATION TABLE
		Annual Compensation							Long Term Compensation
Name and Principal Position	Year		Salary		Bonus	Other Annual Compen- sation (1)			Restricted Stock Awards (2)	Securities Underlying Options (3)	LTIP Payouts (4)			All Other Compen- sation(5)
Dennis R. Wraase   Chairman and Chief   Executive Officer	2004 2003 2002	$	730,250 558,333 455,333	$	438,588 0 257,833	$	9,343 8,124 7,063	$	0 299,997 205,916	0 0 48,000	$	197,069 0 58,946	$	39,028 29,488 22,673
Andrew W. Williams   Senior Vice President	2004 2003 2002	$	330,000 320,000 292,000	$	132,132 0 132,276	$	0 0 0	$	0 0 121,193	0 0 30,000	$	115,962 0 31,800	$	13,541 14,858 13,206
Joseph M. Rigby   Senior Vice President   and Chief Financial   Officer	2004 2003 2002	$	299,167 260,000 250,800	$	119,786 58,656 107,342	$	0 0 0	$	0 0 111,884	0 0 32,051	$	72,088 0 0	$	6,726 7,870 4,716
William J. Sim   President and   Chief Operating Officer	2004 2003 2002	$	281,000 275,000 262,333	$	113,411 0 105,195	$	0 0 0	$	0 0 79,789	0 0 30,000	$	76,353 13,971 31,800	$	15,775 15,015 12,924
Kirk J. Emge   General Counsel	2004 2003 2002	$	232,000 225,000 216,000	$	70,574 0 64,962	$	0 0 0	$	0 0 35,030	0 0 5,100	$	33,500 35,012 0	$	12,047 10,973 10,568

(1)	Other Annual Compensation.  Amounts in this column for each year represent above-market earnings earned by the executive on deferred compensation under the PHI Deferred Compensation Plan assuming retirement at age 65. The amounts are reduced if the executive terminates employment prior to age 62 for any reason other than death, total or permanent disability or a change in control of PHI. In the event of a change in control and termination of the participant's employment, the participant will receive a lump sum payment equal to the net present value of the expected payments at age 65 discounted using the Pension Benefit Guaranty Corporation immediate payment interest rate plus one-half of one percent. Payments to the executives are funded by PHI-owned life insurance policies held in trust. PHI has purchased such policies on participating individuals under a program designed so that if assumptions as to mortality experience, policy return and other factor s are realized, the compensation deferred and the death benefits payable to PHI under such insurance policies will cover all premium payments and benefit payments projected under this program, plus a factor for the use of Pepco funds.
	In addition to the compensation shown in the above Summary Compensation Table, each of the Pepco Named Executive Officers were entitled to one or more of the following personal benefits: financial planning services, tax preparation services, personal use of company-owned automobiles or an automobile allowance, club dues and personal use of company entertainment venues. For each of the Pepco Named Executive Officers, the aggregate value of these perquisites in each of the three years was less than the lesser of $50,000 or 10% of the total annual salary and bonus, and accordingly, consistent with the rules of the Securities and Exchange Commission, the value of these perquisites has not been included in the Table.
(2)	Restricted Stock.  The amount in this column for 2003 for Mr. Wraase represents the dollar value on the grant date of restricted shares of Common Stock awarded under PHI's Long-Term Incentive Plan. The restricted shares granted to Mr. Wraase in 2003 vest on June 1, 2006 if he is continuously employed by the Company through that date. Amounts in this column for 2002 represent the dollar value on the grant date of restricted shares of PHI common stock awarded to each of Messrs. Wraase, Williams, Rigby, Sim and Emge under the Merger Success Integration Program implemented under PHI's Long-Term Incentive Plan. The dollar value in each case is calculated by multiplying the number of restricted shares by the market price of the PHI common stock on the grant date. Twenty percent of the restricted shares

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	granted in 2002 vested on August 1, 2003, and 30% vested on August 1, 2004. The remaining 50% vest on August 1, 2005 if the executive remains employed by the Company through that date. Dividends are paid on the restricted shares. The dollar value in each case is calculated by multiplying the number of restricted shares by the market price of the PHI common stock on the grant date.
	In addition, for Mr. Rigby, amounts in this column for 2002 represent the dollar value on the grant date of 1,500 restricted shares of Conectiv common stock granted to him under the Conectiv Long-Term Incentive Plan. The 1,500 shares were converted in connection with the merger into 1,923 shares of restricted PHI common stock issued under PHI's Long-Term Incentive Plan. The converted shares vest on January 2, 2009 if Mr. Rigby remains employed by PHI through that date. Dividends are paid on the restricted shares.
	The number and aggregate market value of all restricted shares of PHI common stock held by the Pepco Named Executive Officers at December 31, 2004 were: Mr. Wraase, 20,039 shares with a market value of $428,233; Mr. Williams, 3,071 shares with a market value of $65,627; Mr. Rigby, 3,830 shares with a market value of $81,848; Mr. Sim, 2,021 shares with a market value of $43,189; and Mr. Emge, 887 shares with a market value of $18,955.
(3)	Options.  Amounts in this column for Messrs. Wraase, Williams, Sim and Emge represent the stock options granted under the Pepco Long-Term Incentive Plan. At the time of the merger, these options were exchanged on a one-for-one basis for PHI stock options granted under PHI's Long-Term Incentive Plan. In 2002, prior to the merger, Mr. Rigby was awarded 25,000 Conectiv stock options. At the time of the merger, these options were exchanged on a 1 for 1.28205 basis for 32,051 PHI stock options granted under PHI's Long-Term Incentive Plan.
(4)	Incentive Plan Payouts.  Amounts in this column for Messrs. Wraase, Williams, Sim and Emge represent the value of PHI common stock awarded under the Performance Restricted Stock Program, a component of PHI's Long-Term Incentive Plan that vested during the year. The amount shown for 2003 for Mr. Emge is for the performance based award from the Merger Integration Success Plan for the 2003 plan period. The amounts shown for 2002 consist of 33 1/3% of the PHI common stock award from the one-year performance cycle ended December 31, 1999, 33 1/3% of the PHI common stock award from the eight-month performance cycle ended December 31, 1999, and 100% of the PHI common stock award from the three-year cycle ended December 31, 2002 that vested on January 1, 2003. The value of the vested PHI common stock was calculated by multiplying the number of vested shares by the market price of the PHI common stock on the day preceding the vesting date.
(5)	All Other Compensation.  Amounts in this column for 2004 consist of (i) PHI's contributions to the Pepco Savings Plan for Exempt Employees of $10,000, $8,650, $10,000 and $9,911 for Messrs. Wraase, Williams, Sim and Emge, respectively, and Conectiv's contribution to the Conectiv Savings and Investment Plan of $5,610 for Mr. Rigby, (ii) PHI contributions to the Executive Deferred Compensation Plan due to Internal Revenue Service limitations on maximum contributions to the Pepco Savings Plan for Exempt Employees of $18,221 and $545 for Messrs. Wraase and Williams, respectively, and (iii) the term life insurance premiums paid by PHI for Messrs. Wraase, Williams, Rigby, Sim and Emge of $10,807, $4,256, $1,116, $5,775 and $2,136, respectively.

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AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION VALUES
			Number of Shares Underlying UnexercisedOptions at End of Fiscal Year		Value of Unexercised In-the-Money Options at End of Fiscal Year ($) (6)
Name	Shares Acquired on Exercise    (#)	Value Realized   ($)	Exercisable	Unexercisable	Exercisable	Unexercisable
Dennis R. Wraase	0	0	129,843	36,000	0	0
Andrew W. Williams	0	0	61,734	22,500	0	0
Joseph M. Rigby	16,026	$36,464	0	16,025	0	$37,498
William J. Sim	0	0	61,734	22,500	0	0
Kirk J. Emge	0	0	11,475	3,825	0	0

(6) Value of Unexercised In-the-Money Options at End of Fiscal Year.  The value of unexercised in-the-money options at December 31, 2004 is calculated by multiplying the number of shares by the amount by which the fair market value of the PHI common stock on the last trading day of 2004, as reported by the NYSE, exceeds the option exercise price. For Messrs. Wraase, Williams, Sim and Emge, the closing price of the PHI common stock on the last trading day of 2004 was less than the option exercise prices, making the value of the unexercised in-the-money options zero.

LONG-TERM INCENTIVE PLAN-AWARDS IN LAST FISCAL YEAR
Name	Performance or Other Period Until Maturation or      Payout	ThresholdNumber of Shares	TargetNumber of Shares	MaximumNumber of Shares
Dennis R. Wraase	2005-2007	0	45,500	91,000
Andrew W. Williams	2005-2007	0	10,000	20,000
Joseph M. Rigby	2005-2007	0	11,200	22,400
William J. Sim	2005-2007	0	9,800	19,600
Kirk J. Emge	2005-2007	0	4,600	9,200

     Under the Performance Restricted Stock Program established under PHI's Long-Term Incentive Plan, participating executives are entitled to earn shares of Common Stock to the extent one or more pre-established performance criteria are met on a specified performance period. The preceding table sets forth the performance award opportunities granted under the Program in 2004 to each of the Pepco Named Executive Officers. The awards relate to performance over a three-year period beginning on January 1, 2005 and ending on December 31, 2007. Depending on the extent to which the performance objective established by PHI's Compensation/Human Resources Committee is satisfied, the executive will earn some or all of the maximum award of shares of PHI common stock. The performance objective for the 2005 to 2007 performance period is based on PHI's total shareholder return compared to other companies in a peer group comprised of 20 gas and electr ic distribution companies. A participant is eligible to earn a number of shares of PHI common stock ranging from 0% to 200% of the target performance award to the extent that the performance objective is achieved. The performance objectives was fixed at the time the awards are made; however, if, during the course of the performance period, a significant event occurs, as determined in the sole discretion of PHI's Compensation/Human Resources Committee, which

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the Committee expects to have a substantial effect on total shareholder performance during the period, the Committee may revise the targeted performance objective.

     The shares of PHI common stock earned by a participant will be fully vested on the date the performance award is earned.

PEPCO PENSION PLAN TABLE
	Annual Retirement Benefits
	Years in Plan
Average Annual Salary   in Final Three Years     of Employment		15		20		25		30		35		40
$250,000	$	66,000	$	88,000	$	109,000	$	131,000	$	153,000	$	175,000
$350,000	$	92,000	$	123,000	$	153,000	$	184,000	$	214,000	$	245,000
$450,000	$	118,000	$	158,000	$	197,000	$	236,000	$	276,000	$	315,000
$550,000	$	144,000	$	193,000	$	241,000	$	289,000	$	337,000	$	385,000
$650,000	$	171,000	$	228,000	$	284,000	$	341,000	$	398,000	$	455,000
$750,000	$	197,000	$	263,000	$	328,000	$	394,000	$	459,000	$	525,000
$850,000	$	223,000	$	298,000	$	372,000	$	446,000	$	521,000	$	595,000
$950,000	$	249,000	$	333,000	$	416,000	$	499,000	$	582,000	$	665,000
$1,050,000	$	276,000	$	368,000	$	459,000	$	551,000	$	643,000	$	735,000

     The Pepco Holdings Retirement Plan consists of the Pepco General Retirement Plan and the Conectiv Retirement Plan.

     The Pepco General Retirement Plan provides participating employees with at least five years of service with retirement benefits based on the participant's average salary (the term "salary" being equal to the amounts contained in the Salary column of the Summary Compensation Table) for the final three years of employment and the number of years of credited service under the Plan at the time of retirement. Normal retirement under this Plan is age 65. Plan benefits are subject to an offset for any Social Security benefits. Benefits under the Plan may be reduced under provisions of the Internal Revenue Code and by salary deferrals under Pepco's deferred compensation plans (other than the participant's pre-tax contributions made under the Savings Plan). If an executive's retirement benefits under the Plan are reduced by either or both of these limitations, Pepco will pay a supplemental retirement benefit to the eligible executive that is designe d to maintain total retirement benefits at the formula level of the Plan. In addition, for executives who retire at age 59 or older, their retirement benefit will be calculated by adding the average of the highest three annual incentive awards in the last five consecutive years to their average salary over the final three years of their employment. The annual incentive amounts are equal to the amounts shown in the Bonus column of the Summary Compensation Table. The current age, years of credited service and compensation used to determine retirement benefits (including supplemental benefits) for the officers named in the Summary Compensation Table who are participants in the Plan are as follows: Mr. Wraase, age 61, 36 years of credited service and $769,879; Mr. Williams, age 55, 30 years of credited service and $416,872; Mr. Sim, age 60, 35 years of credited service and $374,320; and Mr. Emge, age 55, 18 years of credited service and $288,402. Annual benefits at age 65 (including the effect of the So cial Security offset) are illustrated in the table above.

     Mr. Rigby participates in the Conectiv Retirement Plan and the Conectiv Supplemental Executive Retirement Plan. The Conectiv Retirement Plan is a cash balance pension plan, but also includes certain "grandfathered" rights under the Atlantic City Electric Retirement Plan that apply to employees who

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had attained either 20 years of service or age 50 on or before January 1, 1999. The Conectiv Supplemental Executive Retirement Plan provides supplemental retirement benefits to which the participating executives would be entitled in the absence of federal tax law limitations on the benefits payable under the Conectiv Retirement Plan.

     Under the Conectiv Retirement Plan, a record-keeping account in a participant's name is credited with an amount equal to a percentage of the participant's total pay, including base pay, overtime and bonuses, depending on the participant's age at the end of the plan year. For Mr. Rigby, the percentage currently is 9%. These accounts also receive interest credits equal to prevailing U.S. Treasury Bill rates during the year. In addition, some of the annuity benefits earned by participants under the former Atlantic City Electric Retirement Plan are fully protected as of December 31, 1998, and were converted to an equivalent cash amount and included in each participant's initial cash balance account. Benefits generally become vested after five years of service. When a participant terminates employment, the amount credited to his or her account is converted into an annuity or paid in a lump sum. There is no Social Security offset under the Cone ctiv Retirement Plan. The estimated retirement benefits, including supplemental retirement benefits, payable to Mr. Rigby under the Conectiv Retirement Plan, calculated based on the cash balance formula and including the Atlantic City Electric Retirement Plan credit, if he were to retire at normal retirement age of 65, expressed in the form of a lump sum payment, would be $3,156,000.

     Under the Conectiv Retirement Plan's grandfathering provisions, employees who participated in the Atlantic City Electric Retirement Plan and who met age and service requirements as of January 1, 1999, are assured a minimum retirement benefit calculated for all years of service up to the earlier of December 31, 2008 or retirement according to their original benefit formula under the applicable plan. There is no Social Security offset under the Atlantic City Electric Retirement Plan. This benefit will be compared to the cash balance account and the employee will receive whichever is greater. The benefit is payable in the form of various annuity options or a lump sum. On December 31, 2008, the participant's grandfathered benefit under the Atlantic City Electric Retirement Plan will be frozen, and all future benefit accruals will be under the cash balance formula of the Conectiv Retirement Plan.

     Mr. Rigby was a participant in the Atlantic City Electric Retirement Plan. His annual benefits under the Plan at age 65, as supplemented by the Conectiv Supplemental Executive Retirement Plan, are illustrated in the table below. Mr. Rigby's current years of credited service and earnings used to determine retirement benefits are as follows: age 48, 26 years of credited service and $400,592. Earnings consist of base salary and bonus as shown in Salary and Bonus columns of the Summary Compensation Table.

                    ATLANTIC ELECTRIC PENSION PLAN TABLE

Average Salary and Bonus of the Highest Five Consecutive Years of the Ten Years Preceding Retirement	Annual Retirement Benefits
	Years in Plan
	15		20		25		30		35		40
$200,000	$	48,000	$	64,000	$	80,000	$	96,000	$	112,000	$	128,000
$300,000	$	72,000	$	96,000	$	120,000	$	144,000	$	168,000	$	192,000
$400,000	$	96,000	$	128,000	$	160,000	$	192,000	$	224,000	$	256,000
$500,000	$	120,000	$	160,000	$	200,000	$	240,000	$	280,000	$	320,000
$600,000	$	144,000	$	192,000	$	240,000	$	288,000	$	336,000	$	384,000

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Director Compensation

     The directors of Pepco, all of whom are executive officers of PHI, are not separately compensated for their service as directors.

Employment and Severance Agreements

     Messrs. Wraase, Williams, Sim and Rigby each have employment agreements with PHI. Mr. Wraase's agreement provides for employment through August 1, 2007, and automatically extends until April 1, 2009, unless either PHI or the executive gives notice that it shall not be extended. Mr. Williams', Mr. Sim's and Mr. Rigby's agreements provide for their employment through August 1, 2005, and automatically extend for successive periods of three years thereafter, unless either PHI or the executive has given notice that it shall not be so extended. Each of the employment agreements provides that the executive (i) will receive an annual salary in an amount not less than his base salary in effect as of August 1, 2002, and incentive compensation as determined by the PHI Board of Directors and (ii) will be entitled to participate in retirement plans, fringe benefit plans, supplemental benefit plans and other plans and programs, on the s ame basis as other senior executives of PHI.

     Under each of the employment agreements, the executive is entitled to certain benefits if his employment is terminated prior to the expiration of the initial term of the agreement (or, if applicable, as extended) either (i) by PHI other than for cause, death or disability or (ii) by the executive if his base salary is reduced, he is not in good faith considered for incentive awards, PHI fails to provide him with retirement benefits and other benefits provided to similarly situated executives, he is required to relocate by more than 50 miles from Washington, D.C., or he is demoted from a senior management position. These benefits include: (i) a lump sum payment in cash equal to three times (a) the sum of the executive's highest annual base salary rate in effect during the three-year period preceding termination and (b) the higher of (1) the annual target bonus for the year in which the termination of employment occurs or (2) the highest annual bonus received by the executive in any of the three preceding calendar years and (ii) the executive's annual bonus for the year preceding termination of employment, if not yet paid, and a pro rata portion of the executive's annual bonus for the year in which the executive's employment terminates. In addition, any outstanding shares of restricted stock will become immediately vested, and the executive will be entitled to receive unpaid salary through the date of termination and certain supplemental retirement benefits under existing plans of PHI. Each of the agreements also provides that the executive is entitled to receive a gross-up payment equal to the amount of any federal excise taxes imposed upon compensation payable upon termination of employment and the additional taxes that result from such payment.

     Mr. Emge has entered into a severance agreement with Pepco. The severance agreement provides for the payment of severance benefits to the executive if, within two years following a change in control, any of the following events occur: (i) termination of the employment of the executive by Pepco (or a successor company), other than for cause, death, disability or voluntary normal retirement; (ii) termination of employment by the executive for "good reason," defined as the assignment of duties materially inconsistent with the executive's duties prior to the change in control or a material reduction or alteration of his duties, a reduction in the executive's salary or relocation of the executive by more than 50 miles; (iii) the failure or refusal by a successor company to assume Pepco's obligations under the agreement; or (iv) a material breach of the agreement

374
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by Pepco (or a successor company). The executive also is entitled to severance benefits upon (i) the termination of the executive's employment without cause in contemplation of, but prior to, a change in control or (ii) the occurrence of an event, in contemplation of, but prior to a change in control, constitute "good reason" followed by the executive's voluntary termination of employment within two years after a change in control. The severance benefits consist of: (i) an amount equal to two times the executive's annual base salary (in effect at the time of termination) and annual bonus (average of annual target bonuses during the three years prior to termination) paid in 24 equal monthly installments and (ii) certain welfare benefits for a three-year period after the date of termination. The agreement also provides that the executive is entitled to receive a gross-up payment equal to the amount of any federal excise taxes imposed upon compensation payable upon termination and the additional taxes that result from such payment.

Compensation Committee Interlocks and Insider Participation

     All compensation decisions with respect to the executive officers of Pepco are made by the Compensation/Human Resources Committee of PHI. Each member of the PHI Compensation/Human Resources Committee is an "independent director" as that term is defined by PHI's corporate governance guidelines and the listing standards of the New York Stock Exchange.

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

Item 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
            AND RELATED STOCKHOLDER MATTERS

Pepco Holdings, Inc.

     The information required by Item 12 for Pepco Holdings concerning the security ownership of certain beneficial owners and management is incorporated herein by reference to information contained under the caption "Security Ownership of Certain Beneficial Owners and Management" in its definitive proxy statement for the 2005 Annual Meeting of Shareholders to be filed with the Securities and Exchange Commission on or about March 31, 2005.

     The following table provides information as of December 31, 2004, with respect to the shares of PHI's common stock that may be issued under PHI's existing equity compensation plans.

375
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Equity Compensation Plans Information
Plan Category	(a) Number of Securities to be Issued Upon Exercise ofOutstanding Options	(b) Weighted-Average Exercise Price ofOutstanding Options	(c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding SecuritiesReflected in Column (a))
Equity Compensation Plans Approved by Shareholders (1)	(2)	(2)	9,743,464
Equity Compensation Plans Not Approved by Shareholders (3)	0	0	95,825
Total	0	0	9,839,289

(1) Consists solely of the Pepco Holdings, Inc. Long-Term Incentive Plan.

(2) In connection with the merger of Pepco and Conectiv (i) outstanding options granted under the Potomac Electric Power Company Long-Term Incentive Plan were converted into options to purchase 1,365,941 shares of PHI common stock and (ii) options granted under the Conectiv Incentive Compensation Plan were converted into options to purchase 756,660 shares of PHI common stock, of which 9,615 were forfeited in 2004 and 41,668 were exercised in 2004. Collectively, these outstanding options to purchase an aggregate of 2,063,754 shares of PHI common stock have a weighted average exercise price of $21.8841.

(3) Consists solely of the PHI Stock Compensation Plan for Directors which was terminated on December 31, 2004. Under this plan, in which only directors who are not employees of PHI or any of its subsidiaries participated, one-half of the director's $30,000 annual retainer was paid, at the election of the director, either (i) in shares of PHI common stock or (ii) in PHI common stock equivalents under PHI's Deferred Compensation Plan. PHI common stock equivalents correspond in value to the market price of the PHI common stock, but have no voting rights. When a dividend is paid on the PHI common stock, the PHI common stock equivalent balance is credited with additional PHI common stock equivalents based on the number of shares that could be purchased with the cash amount of the dividend at the then current market price. The balance of the annual retainer and meeting fees was paid to the director in cash or, at the election of the director, was deferred through volunt ary participation in the PHI Deferred Compensation Plan. A director was able to elect to have these optional deferrals credited to the director's account either in the form of PHI common stock equivalents or an account that earns additional credits equal to the prevailing prime interest rate, the return on a specified group of funds or a combination of both. Balances under the PHI Deferred Compensation Plan, including PHI common stock equivalent balances, are paid out in cash, in either a lump sum or installments, commencing at a time selected by the director. On January 1, 2005, the PHI Non-Management Directors Compensation Plan became effective, pursuant to which 500,000 shares of PHI common stock are available for future issuance.

Potomac Electric Power Company

     All of Pepco's voting securities are held by PHI.

     No equity securities of Pepco are issuable under any compensation plan. Accordingly, no Equity Compensation Plans Information table is presented for Pepco.

    The following table sets forth, as of February 2, 2004, for each Pepco director, the Pepco Named Executive Officers and all Pepco directors and Pepco executive officers as a group (i) the number of shares of common stock, $.01 par value, of PHI common stock beneficially owned, (ii) the number of shares of PHI common stock that could be purchased through the exercise of stock options then-currently exercisable or that are scheduled to become exercisable within 60 days thereafter, and (iii) the total beneficial ownership. The common stock is PHI's only class of equity securities. None of the listed persons beneficially owns shares of any class of equity securities of Pepco. Each of the individuals listed, and all directors and executive officers as a group, beneficially owned less than 1% of the outstanding shares of PHI common stock.

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Name of Beneficial Owner	Shares of Common StockOwned (1)	Common Stock AcquirableWithin 60 Days	Total BeneficialOwnership (2)
Thomas S. Shaw	77,417	68,333	145,750
William T. Torgerson	27,358	111,093	138,451
Andrew W. Williams	33,613	76,734	110,347
Dennis R. Wraase	60,524	153,843	214,367
William J. Sim	22,181	76,734	98,915
Joseph M. Rigby	10,245	16,025	26,270
Kirk J. Emge (3)	14,668	14,025	28,693
All Directors and   Executive Officers   as a Group (9 Individuals)	273,027	542,991	816,018

(1)  Includes shares held under Pepco Holdings' Dividend Reinvestment Plan and Employee Savings Plans. Also includes shares awarded under the Pepco Holdings' Long-Term Incentive Plan that will vest over time if the executive officer has the right to vote the shares. Unless otherwise noted, each beneficial owner has sole voting power.

(2)  Consists of the sum of the two preceding columns.

(3)  Includes 1,123 shares owned by Mr. Emge's spouse. Mr. Emge disclaims beneficial ownership of these shares.

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

Item 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Pepco Holdings, Inc.

     None.

Potomac Electric Power Company

     None.

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

Item 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

     The information required by this Item 14 with respect to Pepco Holdings (which includes the information required with respect to Pepco, DPL and ACE) is incorporated herein by reference to Pepco Holdings' definitive proxy statement for the 2005 Annual Meeting of Shareholders to be filed with the Securities and Exchange Commission on or about March 31, 2005.

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Part IV

Item 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a)  Documents List

1.   FINANCIAL STATEMENTS

     The financial statements filed as part of this report consist of:

     (a) The financial statement of each registrant set forth in Item 8. "Financial Statements and Supplemental Data."

     (b) The following unaudited financial statements of Starpower Communications, LLC, an unconsolidated entity in which an indirect subsidiary of Pepco Holdings owned a 50% equity interest, are attached as Exhibit 99.1:

          (1) Balance Sheets dated December 31, 2003 and 2002

          (2) Statements of Operations for the years ended December 31, 2003, 2002 and 2001;

          (3) Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001; and

          (4) Notes to Financial Statements.

2.   FINANCIAL STATEMENT SCHEDULES

     All other financial statement schedules, other than those included below, are omitted because either they are not applicable, or the required information is presented in the financial statements, which are included in Item 8. "Financial Statements and Supplemental Data," herein.

	Registrants
Item	Pepco Holdings	Pepco	DPL	ACE
Schedule I, Condensed Financial   Information of Parent Company	379	N/A	N/A	N/A
Schedule II, Valuation and   Qualifying Accounts	382	382	383	383

378
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     Schedule I Condensed Financial Information of parent Company is submitted below.

PEPCO HOLDINGS, INC. (Parent Company)
STATEMENTS OF EARNINGS
	For the Year Ended December 31,
	2004	2003	2002
	(Dollars in Millions)
OPERATING REVENUE	$    -	$    -	$    -
Depreciation and amortization	3.8	5.9	2.7
Other operation and maintenance	2.5	1.9	(1.6)
OPERATING EXPENSES	6.3	7.8	1.1
OPERATING LOSS	(6.3)	(7.8)	(1.1)
OTHER INCOME (EXPENSES)
Interest and dividend income	0.5	0.3	0.1
Interest expense	(97.6)	(89.2)	(28.7)
Equity in earnings of subsidiaries	315.9	164.6	138.1
	218.8	75.7	109.5
INCOME BEFORE INCOME TAXES	212.5	67.9	108.4
INCOME TAXES	(46.2)	(39.7)	(10.3)
INCOME BEFORE EXTRAORDINARY ITEM	$258.7	$107.6	$118.7
EXTRAORDINARY ITEM (net of taxes of   $4.1 million for the year ended   December 31, 2003)	-	5.9	-
NET INCOME	$258.7	$113.5	$118.7
EARNINGS PER SHARE
Basic and diluted before extraordinary item	$ 1.47	$  .63	$  .91
Basic and diluted extraordinary item	-	.03	-
Basic and diluted earnings     per share of common stock	$ 1.47	$  .66	$  .91

The accompanying Notes are an integral part of the financial information.

379
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PEPCO HOLDINGS, INC. (Parent Company)
BALANCE SHEETS
	As of December 31,
	2004	2003
	(Dollars in Millions)
ASSETS
Current Assets
Cash and cash equivalents	$   95.5	$   73.5
Prepaid and other	28.3	28.2
	123.8	101.7
Investments and Other Assets
Notes receivable from subsidiary companies	1,088.0	994.8
Investment in consolidated companies	4,236.9	4,089.2
Other	54.2	52.4
	5,379.1	5,136.4
Property, Plant and Equipment
Property, plant, and equipment	13.7	13.7
Accumulated depreciation	(11.6)	(7.8)
Net plant in service	2.1	5.9
Total Assets	$5,505.0	$5,244.0
CAPITALIZATION AND LIABILITIES
Current Liabilities
Short-term debt	$  128.6	$  200.0
Accounts payable	4.2	1.8
Interest and taxes accrued	7.1	40.1
	139.9	241.9
Long-Term Debt	1,998.8	1,998.8
Commitments and Contingencies
Capitalization
Common stock, $.01 par value;      authorized 400,000,000 shares;      issued 188,327,510 and             171,769,448 shares, respectively	1.9	1.7
Premium on stock and other capital      contributions	2,566.2	2,246.6
Capital stock expense	(13.5)	(3.3)
Accumulated other comprehensive loss	(52.0)	(22.7)
Retained earnings	863.7	781.0
Total common stockholders' equity	3,366.3	3,003.3
Total Capitalization and Liabilities	$5,505.0	$5,244.0

The accompanying Notes are an integral part of the financial information.

380
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PEPCO HOLDINGS, INC. (Parent Company)
STATEMENTS OF CASH FLOWS
	For the Year Ended December 31,
	2004	2003	2002
	(Dollars in Millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 258.7	$ 113.5	$  118.7
Adjustments to reconcile net income to net     cash provided by operating activities:
Depreciation and amortization	8.5	5.9	2.7
Distributions from related parties          (less than) in excess of earnings	(186.7)	5.9	(138.1)
Extraordinary item	-	(10.0)	-
Deferred income taxes, net	20.7	(27.8)	-
Net change in:
Prepaid and other	(0.1)	0.9	(1.5)
Accounts payable	2.4	(7.2)	9.2
Interest and taxes	(60.5)	18.5	21.5
Other, net	14.3	14.9	65.0
Net cash provided by operating activities	57.3	114.6	77.5
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition of Conectiv, net of cash acquired	-	-	(1,134.7)
Net investment in property, plant and equipment	-	(2.2)	(11.4)
Net cash used by investing activities	-	(2.2)	(1,146.1)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid on common stock	(176.0)	(170.7)	(54.4)
Common stock issued to the Dividend Reinvestment Plan	29.2	31.2	-
Issuance of common stock	288.8	1.6	105.7
Long-term debt issued	-	500.0	1,500.0
Long-term debt redeemed	(200.0)	-	-
Notes receivable from associated companies	(93.2)	(448.6)	(901.8)
Repayments of short-term debt, net	128.6	(210.9)	410.9
Costs of issuances and refinancings	(12.7)	(7.9)	(119.6)
Other financing activities	-	(1.1)	395.3
Net cash (used by) provided by financing activities	(35.3)	(306.4)	1,336.1
Net change in cash and cash equivalents	22.0	(194.0)	267.5
Beginning of year cash and cash equivalents	73.5	267.5	-
End of year cash and cash equivalents	$  95.5	$  73.5	$  267.5

The accompanying Notes are an integral part of the financial information.

NOTES TO FINANCIAL INFORMATION

     These condensed financial statements represent the financial information for Pepco Holdings, Inc. (Parent Company), the parent company of Pepco Holdings, Inc. No other financial statement schedules have been filed either because the required information is not present in amounts sufficient to require submission of the schedule or the information is included in the accompanying consolidated financial statements or the notes to the consolidated financial statements. The statements of earnings and cash flows for 2002 include only post-merger (August 1, 2002) results.

     For information concerning PHI's long-term debt obligations, see Note 7 to the Consolidated Financial Statements included in Item 8 of Part II.

     For information concerning PHI's material contingencies and guarantees, see Note 12 to the Consolidated Financial Statements included in Item 8 of Part II.

    The parent company's majority owned subsidiaries are recorded using the equity method of accounting.

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     Schedule II (Valuation and Qualifying Accounts) for each registrant is submitted below:

Pepco Holdings, Inc.
Col. A	Col. B	Col. C		Col. D	Col. E
		Additions
Description	Balance at Beginningof Period	Charged to Costs andExpenses	Charged to OtherAccounts (a)	Deductions(b)	Balance at End of Period
	(Millions of Dollars)
Year Ended December 31, 2004   Allowance for uncollectible     accounts -customer and     other accounts receivable	$43.5	$23.2	$ .8	$(23.8)	$43.7
Year Ended December 31, 2003   Allowance for uncollectible     accounts - customer and     other accounts receivable	$37.3	$33.5	$ .9	$(28.2)	$43.5
Year Ended December 31, 2002   Allowance for uncollectible     accounts - customer and     other accounts receivable	$9.5	$13.1	$ .8	$13.9	$37.3

(a)	Collection of accounts previously written off.
(b)	Due to the consummation of the merger this amount includes the transfer of Conectiv balances onto Pepco Holdings accounts, net of uncollectible accounts written off.

PEPCO
Col. A	Col. B	Col. C		Col. D	Col. E
		Additions
Description	Balance at Beginningof Period	Charged to Costs andExpenses	Charged to OtherAccounts (a)	Deductions(b)	Balance at End of Period
	(Millions of Dollars)
Year Ended December 31, 2004   Allowance for uncollectible     accounts - customer and     other accounts receivable	$18.4	$ 7.8	$ .8	$ (6.9)	$20.1
Year Ended December 31, 2003   Allowance for uncollectible     accounts - customer and     other accounts receivable	$ 3.6	$20.2	$ .9	$( 6.3)	$18.4
Year Ended December 31, 2002   Allowance for uncollectible     accounts - customer and     other accounts receivable	$ 9.5	$5.7	$ .8	$(12.4)	$3.6

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

382
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DPL
Col. A	Col. B	Col. C		Col. D	Col. E
		Additions
Description	Balance at Beginningof Period	Charged to Costs andExpenses	Charged to OtherAccounts (a)	Deductions(b)	Balance at End of Period
	(Millions of Dollars)
Year Ended December 31, 2004   Allowance for uncollectible     accounts - customer and     other accounts receivable	$10.1	$ 6.3	-	$ (7.7)	$ 8.7
Year Ended December 31, 2003   Allowance for uncollectible     accounts - customer and     other accounts receivable	$14.2	$ 6.4	-	$(10.5)	$10.1
Year Ended December 31, 2002   Allowance for uncollectible     accounts - customer and     other accounts receivable	$17.3	$13.6	-	$(16.7)	$14.2
(a) Collection of accounts previously written off.
(b) Uncollectible accounts written off.

ACE
Col. A	Col. B	Col. C		Col. D	Col. E
		Additions
Description	Balance at Beginningof Period	Charged to Costs andExpenses	Charged to OtherAccounts (a)	Deductions(b)	Balance at End of Period
	(Millions of Dollars)
Year Ended December 31, 2004   Allowance for uncollectible     accounts - customer and     other accounts receivable	$5.3	$ 4.7	-	$ (5.5)	$4.5
Year Ended December 31, 2003   Allowance for uncollectible     accounts - customer and     other accounts receivable	$9.1	$ 2.1	-	$ (5.9)	$5.3
Year Ended December 31, 2002   Allowance for uncollectible     accounts - customer and     other accounts receivable	$7.8	$13.4	-	$(12.1)	$9.1
(a) Collection of accounts previously written off.
(b) Uncollectible accounts written off.
383 _____________________________________________________________________________

3.   Exhibits required by Securities and Exchange Commission Regulation S-K
     (summarized below).

EXHIBITS

     The documents listed below are being filed or have previously been filed on behalf of Pepco Holdings, Inc. (PHI), Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and Atlantic City Electric company (ACE) and are incorporated herein by reference from the documents indicated and made a part hereof.

Exhibit   No.	Registrant(s)	Description of Exhibit	Reference
2	PHI Pepco	Agreement and Plan of Merger, dated as of February 9, 2001, among PHI (formerly New RC, Inc.), Pepco and Conectiv	Exh. 2 to Pepco's Form 8-K, 2/13/01.
2.1	DPL ACE	Amended and Restated Agreement and Plan of Merger, dated as of December 26, 1996, between DPL, Atlantic Energy, Inc., Conectiv and DS Sub, Inc.	Exh. 2(a) to Conectiv's Registration Statement No. 333-18843, 12/26/96.
3.1	PHI	Certificate of Incorporation of PHI	Exh. 3.1 to Form 8-K, 8/2/02.
3.1.1	Pepco	Restated Articles of Incorporation and Articles of Restatement of Pepco	Filed herewith.
3.1.2	DPL	Articles of Restatement of Certificate and Articles of Incorporation (filed in Virginia 8/8/02)	Exh. B.35.1 to PHI's Amendment No. 1 to Form U5B, 2/13/02.
3.1.3	DPL	Corrected Restated Certificate and Articles of Incorporation (filed in Delaware 8/16/02)	Exh. B.35.4 to PHI's Amendment No. 1 to Form U5B, 2/13/02.
3.1.4	DPL	Articles of Correction (filed in Virginia 8/16/02)	Exh. B.35.3 to PHI's Amendment No. 1 to Form U5B, 2/13/02.
3.1.5	ACE	Restated Certificate of Incorporation (filed in New Jersey 8/09/02)	Exh. B.8.1 to PHI's Amendment No. 1 to Form U5B, 2/13/03.
3.2.1	PHI	By-Laws	Exh. 3 to PHI's Form 8-K, 1/28/05.
3.2.2	Pepco	By-Laws	Exh. 3 to Pepco's Form 10-Q, 5/14/03.
3.2.3	DPL	Amended and Restated By-Laws (adopted 8/08/02)	Exh. B.35.2 to PHI's Amendment No. 1 to Form U5B, 2/13/02.
3.2.4	ACE	Amended and Restated By-Laws Company (adopted 8/08/02)	Exh. B.8.3 to PHI's Amendment No. 1 to Form U5B, 2/13/03.

384
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4.1	PHI Pepco	Mortgage and Deed of Trust dated July 1, 1936, of Pepco to The Bank of New York as Successor Trustee, securing First Mortgage Bonds of Pepco, and Supplemental Indenture dated July 1, 1936	Exh. B-4 to First Amendment, 6/19/36, to Pepco's Registration Statement No. 2-2232.
		Supplemental Indentures, to the aforesaid Mortgage and Deed of Trust, dated - December 10, 1939	Exh. B to Pepco's Form 8-K, 1/3/40.
		July 15, 1942	Exh. B-1 to Amendment No. 2, 8/24/42, and B-3 to Post-Effective Amendment, 8/31/42, to Pepco's Registration Statement No. 2-5032.
		October 15, 1947	Exh. A to Pepco's Form 8-K, 12/8/47.
		December 31, 1948	Exh. A-2 to Pepco's Form 10-K, 4/13/49.
		December 31, 1949	Exh. (a)-1 to Pepco's Form 8-K, 2/8/50.
		February 15, 1951	Exh. (a) to Pepco's Form 8-K, 3/9/51.
		February 16, 1953	Exh. (a)-1 to Pepco's Form 8-K, 3/5/53.
		March 15, 1954 and March 15, 1955	Exh. 4-B to Pepco's Registration Statement No. 2-11627, 5/2/55.
		March 15, 1956	Exh. C to Pepco's Form 10-K, 4/4/56.
		April 1, 1957	Exh. 4-B to Pepco's Registration Statement No. 2-13884, 2/5/58.
		May 1, 1958	Exh. 2-B to Pepco's Registration Statement No. 2-14518, 11/10/58.
		May 1, 1959	Exh. 4-B to Amendment No. 1, 5/13/59, to Pepco's Registration Statement No. 2-15027.

385
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May 2, 1960	Exh. 2-B to Pepco's Registration Statement No. 2-17286, 11/9/60.
April 3, 1961	Exh. A-1 to Pepco's Form 10-K, 4/24/61.
May 1, 1962	Exh. 2-B to Pepco's Registration Statement No. 2-21037, 1/25/63.
May 1, 1963	Exh. 4-B to Pepco's Registration Statement No. 2-21961, 12/19/63.
April 23, 1964	Exh. 2-B to Pepco's Registration Statement No. 2-22344, 4/24/64.
May 3, 1965	Exh. 2-B to Pepco's Registration Statement No. 2-24655, 3/16/66.
June 1, 1966	Exh. 1 to Pepco's Form 10-K, 4/11/67.
April 28, 1967	Exh. 2-B to Post-Effective Amendment No. 1 to Pepco's Registration Statement No. 2-26356, 5/3/67.
July 3, 1967	Exh. 2-B to Pepco's Registration Statement No. 2-28080, 1/25/68.
May 1, 1968	Exh. 2-B to Pepco's Registration Statement No. 2-31896, 2/28/69.
June 16, 1969	Exh. 2-B to Pepco's Registration Statement No. 2-36094, 1/27/70.
May 15, 1970	Exh. 2-B to Pepco's Registration Statement No. 2-38038, 7/27/70.
September 1, 1971	Exh. 2-C to Pepco's Registration Statement No. 2-45591, 9/1/72.

386
_____________________________________________________________________________

June 17, 1981	Exh. 2 to Amendment No. 1 to Form 8-A, 6/18/81.
November 1, 1985	Exh. 2B to Form 80A, 11/1/85.
September 16, 1987	Exh. 4-B to Registration Statement No. 33-18229, 10/30/87.
May 1, 1989	Exh. 4-C to Registration Statement No. 33-29382, 6/16/89.
May 21, 1991	Exh. 4 to Form 10-K, 3/27/92,
May 7, 1992	Exh. 4 to Pepco's Form 10-K, 3/26/93.
September 1, 1992	Exh. 4 to Pepco's Form 10-K, 3/26/93.
November 1, 1992	Exh. 4 to Pepco's Form 10-K, 3/26/93.
March 1, 1993	Exh. 4 to Pepco's Form 10-K, 3/26/93.
July 1, 1993	Exh. 4.4 to Pepco's Registration Statement No. 33-49973, 8/11/93.
August 20, 1993	Exh. 4.4 to Pepco's Registration Statement No. 33-50377, 9/23/93.
September 30, 1993	Exh. 4 to Pepco's Form 10-K, 3/25/94.
October 1, 1993	Exh. 4 to Pepco's Form 10-K, 3/25/94.
February 10, 1994	Exh. 4 to Pepco's Form 10-K, 3/25/94.
February 11, 1994	Exh. 4 to Pepco's Form 10-K, 3/25/94.
March 10, 1995	Exh. 4.3 to Registration Statement No. 61379, 7/28/95.
September 6, 1995	Exh. 4 to Pepco's Form 10-K, 4/1/96.
September 7, 1995	Exh. 4 to Pepco's Form 10-K, 4/1/96.
October 2, 1997	Exh. 4 to Pepco's Form 10-K, 3/26/98.

387
_____________________________________________________________________________

		November 17, 2003	Exhibit 4.1 to Pepco's Form 10-K, 3/11/04.
		March 16, 2004	Exh. 4.3 to Pepco's Form 8-K, 3/23/04.
4.2	PHI Pepco	Indenture, dated as of July 28, 1989, between Pepco and The Bank of New York, Trustee, with respect to Pepco's Medium-Term Note Program	Exh. 4 to Pepco's Form 8-K, 6/21/90.
4.3.1	PHI Pepco	Form of 4.95% Senior Note due November 15, 2013	Exh. 4.1 to Pepco's Form 8-K, 11/21/03.
4.3.2	PHI Pepco	Senior Note Indenture dated November 17, 2003	Exh. 4.2 to Pepco's Form 8-K, 11/21/03.
4.4	PHI DPL	Mortgage and Deed of Trust of Delaware Power & Light Company to the New York Trust Company, Trustee, (the Chase Manhattan Bank, successor Trustee) dated as of October 1, 1943 and copies of the First through Sixty-Eighth Supplemental Indentures thereto	Exh. 4-A to DPL's Registration Statement No. 33-1763, 11/27/85.
		Sixty-Ninth Supplemental Indenture	Exh. 4-B to DPL's Registration Statement No. 33-39756, 4/03/91.
		Seventieth through Seventy-Fourth Supplemental Indentures	Exhs. 4-B to DPL's Registration Statement No. 33-24955, 10/13/88.
		Seventy-Fifth through Seventy-Seventh Supplemental Indentures	Exhs. 4-D, 4-E & 4-F to DPL's Registration Statement No. 33-39756, 4/03/91.
		Seventy-Eighth and Seventy-Ninth Supplemental Indentures	Exhs. 4-E & 4-F to DPL's Registration Statement No. 33-46892, 4/1/92.
		Eightieth Supplemental Indenture	Exh. 4 to DPL's Registration Statement No. 33-49750, 7/17/92.
		Eighty-First Supplemental Indenture	Exh. 4-G to DPL's Registration Statement No. 33-57652, 1/29/93.
		Eighty-Second Supplemental Indenture	Exh. 4-H to DPL's Registration Statement No. 33-63582, 5/28/93.

388
_____________________________________________________________________________

		Eighty-Third Supplemental Indenture	Exh. 99 to DPL's Registration Statement No. 33-50453, 10/1/93.
		Eighty-Fourth through Eighty-Eighth Supplemental Indentures	Exhs. 4-J, 4-K, 4-L, 4-M & 4-N to DPL's Registration Statement No. 33-53855, 1/30/95.
		Eighty-Ninth and Ninetieth Supplemental Indentures	Exhs. 4-K & 4-L to DPL's Registration Statement No. 333-00505, 1/29/96.
4.5	PHI DPL	Indenture between DPL and The Chase Manhattan Bank (ultimate successor to Manufacturers Hanover Trust Company), as Trustee, dated as of November 1, 1988	Exh. No. 4-G to DPL's Registration Statement No. 33-46892, 4/1/92.
4.6	PHI DPL	Indenture (for Unsecured Subordinated Debt Securities relating to Trust Securities) between DPL and Wilmington Trust Company, as Trustee, dated as of October 1, 1996.	Exh. No. 4-S to DPL's Registration Statement No. 333-20715, 1/30/97.
4.7	PHI DPL	Officer's Certificate dated October 3, 1996, establishing the 8.125% Junior Subordinated Debentures, Series I, Due 2036	Exh. No.4-T to DPL's Registration Statement No. 333-20715, 1/30/97.
4.8	PHI DPL	Guarantee Agreement between DPL, as Guarantor, and Wilmington Trust Company, as Trustee, dated as of October 1, 1996	Exh. 4-U to DPL's Registration Statement No. 333-20715, 1/30/97.
4.9	PHI DPL	Amended and Restated Trust Agreement between DPL, as Depositor, and Wilmington Trust Company, Barbara S. Graham, Edric R. Mason and Donald P. Connelly, as Trustees, dated as of October 1, 1996	Exh. 4-V to DPL's Registration Statement No. 333-20715, 1/30/97.
4.10	PHI DPL	Agreement as to Expenses and Liabilities dated as of October 1, 1996, between DPL and Delmarva Power Financing I	Exh. 4-W to DPL's Registration Statement No. 333-20715, 1/30/97.
4.11	PHI ACE	Mortgage and Deed of Trust, dated January 15, 1937, between Atlantic City Electric Company and The Bank of New York (formerly Irving Trust Company)	Exh. 2(a) to ACE's Registration Statement No. 2-66280, 12/21/79.
		Supplemental Indentures, to the aforesaid Mortgage and Deed of Trust, dated as of -

389
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June 1, 1949	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
July 1, 1950	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
November 1, 1950	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
March 1, 1952	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
January 1, 1953	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
March 1, 1954	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
March 1, 1955	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
January 1, 1957	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
April 1, 1958	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
April 1, 1959	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
March 1, 1961	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
July 1, 1962	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
March 1, 1963	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.

390
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February 1, 1966	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
April 1, 1970	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
September 1, 1970	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
May 1, 1971	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
April 1, 1972	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
June 1, 1973	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
January 1, 1975	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
May 1, 1975	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
December 1, 1976	Exh. 2(b) to ACE's Registration Statement No. 2-66280, 12/21/79.
January 1, 1980	Exh. 4(e) to ACE's Form 10-K, 3/25/81.
May 1, 1981	Exh. 4(a) to ACE's Form 10-Q, 8/10/81.
November 1, 1983	Exh. 4(d) to ACE's Form 10-K, 3/30/84.
April 15, 1984	Exh. 4(a) to ACE's Form 10-Q, 5/14/84.
July 15, 1984	Exh. 4(a) to ACE's Form 10-Q, 8/13/84.
October 1, 1985	Exh. 4 to ACE's Form 10-Q, 11/12/85.
May 1, 1986	Exh. 4 to ACE's Form 10-Q, 5/12/86.

391
_____________________________________________________________________________

		July 15, 1987	Exh. 4(d) to ACE's Form 10-K, 3/28/88.
		October 1, 1989	Exh. 4(a) to ACE's Form 10-Q for quarter ended 9/30/89.
		March 1, 1991	Exh. 4(d)(1) to ACE's Form 10-K, 3/28/91.
		May 1, 1992	Exh. 4(b) to ACE's Registration Statement 33-49279, 1/6/93.
		January 1, 1993	Exh. 4.05(hh) to ACE's Registration Statement 333-108861, 9/17/03
		August 1, 1993 September 1, 1993	Exh. 4(a) & 4(b) to ACE's Form 10-Q, 11/12/93.
		November 1, 1993	Exh. 4(c)(1) to ACE's Form 10-K, 3/29/94.
		June 1, 1994	Exh. 4(a) to ACE's Form 10-Q, 8/14/94.
		October 1, 1994	Exh. 4(a) to ACE's Form 10-Q, 11/14/94.
		November 1, 1994	Exh. 4(c)(1) to ACE's Form 10-K, 3/21/95.
		March 1, 1997	Exh. 4(b) to ACE's Form 8-K, 3/24/97.
		April 1, 2004	Exh. 4.3 to ACE's Form 8-K, 4/6/04.
		August 10, 2004	Exh. 4 to PHI's Form 10-Q, 11/8/04.
4.12	PHI ACE	Indenture dated as of March 1, 1997 between Atlantic City Electric Company and The Bank of New York	Exh. 4(e) to ACE's Form 8-K, 3/24/97.
4.13	PHI	Issuing and Paying Agency Agreement between Potomac Capital Investment Corporation and The Bank of New York dated April 29, 1998	Exh. 4.16 to PHI's Form 10-K, 3/28/03.
4.14	PHI	Issuing and Paying Agency Agreement between Potomac Capital Investment Corporation and The Bank of New York dated July 7, 2000	Exh. 4.17 to PHI's Form 10-K, 3/28/03.
4.15	PHI	Indenture between PHI and The Bank of New York, as Trustee dated September 6, 2002	Exh. 4.03 to PHI's Registration Statement No. 333-100478, 10/10/02.

392
_____________________________________________________________________________

4.16	PHI	Form of 7.45% Note due August 15, 2032.	Exh. 4.19 to PHI's Form 10-K, 3/28/03.
4.17	PHI	Form of 6.45% Note due August 15, 2012.	Exh. 4.20 to PHI's Form 10-K, 3/28/03.
4.18	PHI	Form of 5.50% Note due August 15, 2007.	Exh. 4.21 to PHI's Form 10-K, 3/28/03.
4.19	PHI	Form of 3.75% Note due February 15, 2006.	Exh. 4.1 to PHI's Form 8-K, 1/17/03.
4.20	PHI	Form of 4.00% Notes due May 15, 2010	Exh. 4.2 to PHI's Form 8-K, 5/27/03.
4.21	PHI ACE	Indenture dated as of December 19, 2002 between Atlantic City Electric Transition Funding LLC (ACE Funding) and The Bank of New York (BONY)	Exh. 4.1 to ACE Funding's Form 8-K, 12/23/02.
4.22	PHI ACE	2002-1 Series Supplement dated as of December 19, 2002 between ACE Funding and BONY	Exh. 4.2 to ACE Funding's Form 8-K, 12/23/02.
4.23	PHI ACE	2003-1 Series Supplement dated as of December 23, 2003 between ACE Funding and BONY	Exh. 4.2 to ACE Funding's Form 8-K, 12/23/03.
4.24	PHI Pepco	Form of Senior Note due 2014	Exh. 4.1 to Pepco's Form 8-K, 3/23/04.
4.25	PHI Pepco	Form of Senior Note due 2034	Exh. 4.2 to Pepco's Form 8-K, 3/23/04.
4.26	PHI ACE	Indenture, dated as of April 1, 2004, with The Bank of New York, as trustee	Exh. 4.2 to ACE's Form 8-K, 4/6/04.
4.27	PHI ACE	Form of 5.80% Senior Notes due May 15, 2034	Exh. 4.1 to ACE's Form 8-K, 4/6/04.
4.28	PHI DPL	Form of 5.00% Notes due November 15, 2014	Exh. 4.1 to DPL's Form 8-K, 11/18/04.
10.1	PHI	Employment Agreement of Dennis R. Wraase*	Exh. 10.2 to PHI's Form 10-Q, 8/9/02.
10.2	PHI	Employment Agreement of William T. Torgerson*	Exh. 10.3 to PHI's Form 10-Q, 8/9/02.
10.3	PHI	Employment Agreement of Andrew W. Williams*	Exh. 10.4 to PHI's Form 10-Q, 8/9/02.
10.4	PHI	Employment Agreement of Thomas S. Shaw*	Exh. 10.5 to PHI's Form 10-Q, 8/9/02.
10.5	PHI	Employment Agreement of Eddie R. Mayberry*	Exh. 10.6 to PHI's Form 10-Q, 8/9/02.
10.6	PHI	Employment Agreement of Joseph M. Rigby*	Exh. 10.8 to PHI's Form 10-Q, 8/9/02.
10.7	PHI	Employment Agreement of William H. Spence*	Exh. 10.9 to PHI's Form 10-Q, 8/9/02.

393
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10.8	PHI	Employment Agreement of William J. Sim*	Exh. 10.10 to PHI's Form 10-Q, 8/9/02.
10.9	PHI	Employment Agreement of James L. Lavin*	Exh. 10.11 to PHI's Form 10-K, 3/28/03.
10.10	PHI Pepco	Form of Severance Agreement between Potomac Electric Power Company and Kirk J. Emge*	Exh. 10.12 to PHI's Form 10-K, 3/28/03.
10.11	PHI	Conectiv Change-in-Control Severance Plan For Certain Executive Officers*	Exh. 10-C to Conectiv's Form 10-K, 3/15/01.
10.12	PHI	Conectiv Change-in-Control Severance Plan For Certain Select Employees*	Exh. 10-D to Conectiv's Form 10-K, 3/15/01.
10.13	PHI	Pepco Holdings, Inc. Long-Term Incentive Plan*	Annex I to PHI's Registration Statement No. 333-57042, 3/14/01.
10.14	PHI	Pepco Holdings, Inc. Stock Compensation Plan for Directors*	Exh. 10.17 to PHI's Form 10-K, 3/28/03.
10.15	PHI	Pepco Holdings, Inc. Executive Performance Supplemental Retirement Plan*	Exh. 10.18 to PHI's Form 10-K, 3/28/03.
10.16	PHI	Pepco Holdings, Inc. Supplemental Executive Retirement Plan*	Exh. 10.19 to PHI's Form 10-K, 3/28/03.
10.17	PHI	Pepco Holdings, Inc. Supplemental Benefit Plan*	Exh. 10.20 to PHI's Form 10-K, 3/28/03.
10.18	PHI	Pepco Holdings, Inc. Revised and Restated Executive and Director Deferred Compensation Plan*	Exh. 10.21 to PHI's Form 10-K, 3/28/03.
10.19	PHI Pepco	Potomac Electric Power Company Director and Executive Deferred Compensation Plan*	Exh. 10.22 to PHI's Form 10-K, 3/28/03.
10.20	PHI Pepco	Potomac Electric Power Company Long-Term Incentive Plan*	Exh. 4 to Pepco's Form S-8, 6/12/98.
10.21	PHI	Conectiv Incentive Compensation Plan*	Exh. 99(e) to Conectiv's Registration Statement No. 333-18843, 12/26/96.
10.22	PHI	Conectiv Deferred Compensation Plan*	Exh. 10-B to Conectiv's Form 10-K, 3/26/99.
10.23	PHI	Conectiv Supplemental Executive Retirement Plan*	Exh. 10.26 to PHI's Form 10-K, 3/28/03.

394
_____________________________________________________________________________

10.24	Pepco	Asset Purchase and Sale Agreement for Generating Plants and Related Assets by and between Potomac Electric Power Company and Southern Energy, Inc. dated June 7, 2000, including Exhibits A through M	Exh. 10 to Pepco's Form 8-K, 6/13/00.
10.25	Pepco	Amendment No. 1, dated September 18, 2000 to Asset Purchase and Sale Agreement for Generating Plants and Related Assets by and between Potomac Electric Power Company and Southern Energy, Inc., dated June 7, 2000, including Exhibits A-1, A-2 and A-3	Exh. 10.1 to Pepco's Form 8-K, 12/19/00.
10.26	Pepco	Amendment No. 2, dated December 19, 2000, to Asset Purchase and Sale Agreement for Generating Plants and Related Assets by and between Potomac Electric Power Company and Southern Energy, Inc., dated June 7, 2000	Exh. 10.2 to Pepco's Form 8-K, 12/19/00.
10.27	PHI Pepco	Transition Power Agreement dated December 19, 2000 -- District of Columbia	Exh. 10.3 to Pepco's Form 8-K, 12/19/00.
10.28	PHI Pepco	Transition Power Agreement dated December 19, 2000 -- Maryland.	Exh. 10.4 to Pepco's Form 8-K, 12/19/00.
10.29	PHI DPL	Purchase and Sale Agreement By and Between Delmarva Power & Light Company and NRG Energy Inc. dated January 18, 2000	Exh. 10-A to DPL's Form 10-K, 4/02/01.
10.30	PHI DPL	Purchase and Sale Agreement By and Between Delmarva Power & Light Company and NRG Energy Inc. dated January 18, 2000	Exh. 10-B to DPL's Form 10-K, 4/02/01.
10.31	ACE	Bondable Transition Property Sale Agreement between ACE Funding and ACE dated as of December 19, 2002	Exh. 10.1 to ACE Funding's Form 8-K, 12/23/02.
10.32	ACE	Bondable Transition Property Servicing Agreement between ACE Funding and ACE dated as of December 19, 2002	Exh. 10.2 to ACE Funding's Form 8-K, 12/23/02.

395
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10.33	PHI Pepco DPL ACE	3-Year Credit Agreement, dated July 29, 2003, among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company, Atlantic City Electric Company, Bank One, NA, as agent, and the Lenders named therein among the Registrants and Bank One, NA, as administrative agent	Exh. 10.2 to PHI's Form 10-Q, 8/13/03.
10.34	PHI Pepco	Settlement Agreement and Release dated October 24, 2003, between and Among, Potomac Electric Power Company, Mirant American Energy Marketing, LP, and Mirant Corporation	Exh. 10.1 to PHI's Form 8-K, 10/24/03.
10.35	PHI Pepco	Amendment to Transition Power Agreement (Maryland) dated October 24,2003	Exh. 10.2 to PHI's Form 8-K, 10/24/03.
10.36	PHI Pepco	Amendment to Transition Power Agreement (District of Columbia) dated October 24,2003	Exh. 10.3 to PHI's Form 8-K, 11/20/03.
10.37	PHI Pepco	Amended Settlement Agreement and Release dated October 24, 2003, between and Among, Potomac Electric Power Company, Mirant American Energy Marketing, LP, and Mirant Corporation	Exh. 10.1 to PHI's Form 8-K, 10/24/03.
10.38	PHI Pepco	Purchase Agreement, dated March 15, 2004, with Credit Suisse First Boston LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, on their own behalf and on behalf of Fleet Securities, Inc., SunTrust Capital Markets, Inc., BNY Capital Markets, Inc., Citigroup Global Markets Inc. and McDonald Investments Inc.	Exh. 1.1 to Pepco's Form 8-K, 3/23/04.
10.39	PHI ACE	Purchase Agreement, dated April 1, 2004, with Banc One Capital Markets, Inc., Scotia Capital (USA) Inc., and Wachovia Capital Markets, LLC	Exh. 1 to ACE's Form 8-K, 4/6/04.
10.40	PHI	Conectiv Deferred Compensation Plan*	Exh. 10.1 to PHI's Form 10-Q, 8/6/04.

396
_____________________________________________________________________________

10.41	PHI Pepco DPL ACE	5-Year Credit Agreement, dated July 26, 2004, among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company, Atlantic City Electric Company, the Lenders named therein, and Bank One N.A., as administrative agent	Exh. 10.2 to PHI's Form 10-Q, 8/6/04.
10.42	PHI	Purchase Agreement, dated as of September 9, 2004, with Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse First Boston LLC and each of the Underwriters named on Schedule A of the Purchase Agreement	Exh. 1.1 to PHI's Form 8-K, 9/13/04.
10.43	PHI Pepco	Employment Agreement of Anthony J. Kamerick*	Exh. 10.1 to PHI's Form 10-Q, 11/8/04.
10.44	PHI	Form of Employee Non-Qualified Stock Option Agreement*	Exh. 10.2 to PHI's Form 10-Q, 11/8/04.
10.45	PHI	Form of Director Non-Qualified Stock Option Agreement*	Exh. 10.3 to PHI's Form 10-Q, 11/8/04.
10.46	PHI	Form of Election Regarding Payment of Director Retainer/Fees*	Exh. 10.4 to PHI's Form 10-Q, 11/8/04.
10.47	PHI	Form of Executive and Director Deferred Compensation Plan Executive Deferral Agreement*	Exh. 10.5 to PHI's Form 10-Q, 11/8/04.
10.48	PHI	Form of Executive Incentive Compensation Plan Participation Agreement*	Exh. 10.6 to PHI's Form 10-Q, 11/8/04.
10.49	PHI	Form of Restricted Stock Agreement*	Exh. 10.7 to PHI's Form 10-Q, 11/8/04.
10.50	PHI	Form of Election with Respect to Stock Tax Withholding*	Exh. 10.8 to PHI's Form 10-Q, 11/8/04.
10.51	PHI DPL	Purchase Agreement, dated as of November 16, 2004, with Credit Suisse First Boston LLC, Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, and each of the Underwriters named on Schedule A of the Purchase Agreement	Exh. 1.1 to DPL's Form 8-K, 11/18/04
10.52	PHI Pepco	Loan Agreement, dated as of December 3, 2004, between Potomac Electric Power Company and The Royal Bank of Scotland Finance (Ireland).	Exh. 10.1 to PHI's Form 8-K, 12/8/04.

397
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10.53	PHI	Short Term Loan Agreement, dated as of December 14, 2004, between Pepco Holdings, Inc. and Mizuho Corporate Bank (USA)	Exh. 10.1 to PHI's Form 8-K, 12/17/04.
10.54	PHI	Non-Management Directors Compensation Plan dated as of December 16, 2004*	Exh. 10.2 to PHI's Form 8-K, 12/17/04.
10.55	PHI	Executive Annual Incentive Compensation Plan dated as of December 16, 2004*	Exh. 10.3 to PHI's Form 8-K, 12/17/04.
10.56	PHI	Non-Management Director Compensation Arrangements*	Filed herewith.
10.57	PHI	Form of Election regarding Non-Management Directors Compensation Plan*	Filed herewith.
10.58	PHI	PHI Named Executive Officer 2005 Compensation Determinations*	Filed herewith.
10.59	Pepco	Pepco Named Executive Officer 2005 Compensation Determinations*	Filed herewith.
10.60	PHI	Employment Agreement of John M. Derrick, Jr.*	Exh. 10.1 to PHI's Form 10-Q, 8/9/02.
10.61	PHI	Amendment No. 1 to Employment Agreement of John M. Derrick, Jr.*	Exh. 10.1 to PHI's Form 10-Q, 11/13/03.
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.
21	PHI Pepco DPL ACE	Subsidiaries of the Registrant	Filed herewith.
23.1	PHI	Consent of Independent Registered Public Accounting Firm	Filed herewith.
23.2	Pepco	Consent of Independent Registered Public Accounting Firm	Filed herewith.
23.3	DPL	Consent of Independent Registered Public Accounting Firm	Filed herewith.
23.4	ACE	Consent of Independent Registered Public Accounting Firm	Filed herewith.

398
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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.
99.1	PHI	Unaudited Financial Statements of Starpower, LLC	Filed herewith.

* Management contract or compensatory plan or arrangement.

     Regulation S-K Item 10(d) requires Registrants to identify the physical location, by SEC file number reference of all documents that are incorporated by reference and have been on file with the SEC for more than five years. The SEC file number references for Pepco Holdings, Inc., those of its subsidiaries that are registrants, Conectiv and ACE Funding are provided below:

Pepco Holdings, Inc. in file number 001-31403

Potomac Electric Power Company in file number 001-1072

Conectiv in file number 001-13895

Delmarva Power & Light Company in file number 001-1405

Atlantic City Electric Company in file number 001-3559

Atlantic City Electric Transition Funding LLC in file number 333-59558

     In accordance with Regulation S-K Item 601(b)(4)(iii) the following instruments that define the rights of holders of long-term debt of PHI and its consolidated subsidiaries are omitted: Loan Agreements relating to DPL unsecured Tax-Exempt Bonds, Indenture relating to Conectiv medium-term notes, 7.36% and 6.9% recourse notes and 6.57% non-recourse notes relating to PCI debt, and the Amended and Restated Assignment and Security Agreement relating to the 7.85% Secured Note of Pepco Energy Services. PHI agrees to furnish a copy of any such omitted instrument to the SEC upon request.

399
_____________________________________________________________________________

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

(c)  Exhibits

Exhibit 11   Statements Re. Computation of Earnings Per Common Share

     The information required by this Exhibit is included in Note 10 of the "Notes to Consolidated Financial Statements," which is included in Exhibit 13.

400
_____________________________________________________________________________

Exhibit 12.1  Statements Re. Computation of Ratios

PEPCO HOLDINGS

		For the Year Ended December 31,
		2004	2003	2002	2001	2000
		(Dollar Amounts in Millions)
Income before extraordinary item (a)		$255.5	$211.1	$220.2	$192.3	$369.1
Income tax expense		173.2	65.9	124.1	83.5	341.2
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense		376.5	381.4	227.2	162.0	221.5
Other interest		20.6	21.7	21.0	23.8	23.6
Preferred dividend requirements     of subsidiaries		2.8	13.9	20.6	14.2	14.7
Total fixed charges		399.9	417.0	268.8	200.0	259.8
Nonutility capitalized interest		(.1)	(10.2)	(9.9)	(2.7)	(3.9)
Income before extraordinary   item, income tax expense,   and fixed charges		$828.5	$683.8	$603.2	$473.1	$966.2
Total fixed charges, shown above		399.9	417.0	268.8	200.0	259.8
Increase preferred stock dividend   requirements of subsidiaries to   a pre-tax amount		1.9	4.3	11.6	6.2	13.5
Fixed charges for ratio   computation		$401.8	$421.3	$280.4	$206.2	$273.3
Ratio of earnings to fixed charges   and preferred dividends		2.06	1.62	2.15	2.29	3.54
(a)	Excludes losses on equity investments.

401
_____________________________________________________________________________

Exhibit 12.2  Statements Re. Computation of Ratios

PEPCO

		For the Year Ended December 31,
		2004	2003	2002	2001	2000
		(Dollar Amounts in Millions)
Net income (a)		$ 96.6	$104.6	$141.2	$192.3	$369.1
Income tax expense		56.7	69.1	80.3	83.5	341.2
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense		80.7	81.4	112.2	162.0	221.5
Other interest		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		95.0	102.2	138.7	195.0	254.3
Nonutility capitalized interest		-	-	(.2)	(2.7)	(3.9)
Income before income tax expense   and fixed charges		$248.3	$275.9	$360.0	$468.1	$960.7
Ratio of earnings to fixed charges		2.61	2.70	2.60	2.40	3.78
Total fixed charges, shown above		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		1.6	5.5	7.8	7.2	10.6
Total Fixed Charges and   Preferred Dividends		$ 96.6	$107.7	$146.5	$202.2	$264.9
Ratio of earnings to fixed charges   and preferred dividends		2.57	2.56	2.46	2.32	3.63
(a)	Excludes losses on equity investments.

402
_____________________________________________________________________________

Exhibit 12.3  Statements Re. Computation of Ratios

DELMARVA POWER & LIGHT COMPANY

	For the Year Ended December 31,
	2004	2003	2002	2001	2000
	(Dollar Amounts in Millions)
Net income	$ 66.3	$ 53.2	$ 49.7	$200.6	$141.8
Income tax expense	49.7	36.4	33.7	139.9	81.5
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense	33.0	37.2	44.1	68.5	77.1
Other interest	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	35.2	42.7	53.4	77.6	90.3
Nonutility capitalized interest	-	-	-	-	-
Income before income tax expense   and fixed charges	$151.2	$132.3	$136.8	$418.1	$313.6
Ratio of earnings to fixed charges	4.30	3.10	2.56	5.39	3.47
Total fixed charges, shown above	35.2	42.7	53.4	77.6	90.3
Preferred dividend requirements,   adjusted to a pre-tax amount	1.7	1.7	2.9	6.3	7.7
Total fixed charges and   preferred dividends	$ 36.9	$ 44.4	$ 56.3	$ 83.9	$  98.0
Ratio of earnings to fixed charges   and preferred dividends	4.10	2.98	2.43	4.98	3.20

403
_____________________________________________________________________________

Exhibit 12.4  Statements Re. Computation of Ratios

ATLANTIC CITY ELECTRIC COMPANY

	For the Year Ended December 31,
	2004	2003	2002	2001	2000
	(Dollar Amounts in Millions)
Income before extraordinary item	$ 64.6	$ 41.5	$ 28.2	$ 75.5	$ 54.4
Income tax expense	42.3	27.3	16.3	46.7	36.7
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense	62.2	63.7	55.6	62.2	76.2
Other interest	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	65.6	68.1	65.6	73.1	88.3
Income before extraordinary   item, income tax expense and   fixed charges	$172.5	$136.9	$110.1	$195.3	$179.4
Ratio of earnings to fixed charges	2.63	2.01	1.68	2.67	2.03
Total fixed charges, shown above	65.6	68.1	65.6	73.1	88.3
Preferred dividend requirements   adjusted to a pre-tax amount	.5	.5	1.1	2.7	3.6
Total fixed charges and   preferred dividends	$ 66.1	$ 68.6	$ 66.7	$ 75.8	$ 91.9
Ratio of earnings to fixed charges   and preferred dividends	2.61	2.00	1.65	2.58	1.95

404
_____________________________________________________________________________

Exhibit 21    Subsidiaries of the Registrants

Name of Company	Jurisdiction of Incorporation or Organization
Pepco Holdings, Inc.	DE
Potomac Electric Power Company	DC & VA
Gridco International L.L.C.	DE
POM Holdings, Inc.	DE
Microcell Corporation	NC
Pepco Energy Services, Inc.	DE
Pepco Building Services, Inc.	DE
MET Electrical Testing Company, Inc.	DE
W.A.Chester, LLC	DE
W.A. Chester Corporation	DE
Engineered Services, Inc.	DE
Severn Construction Services, LLC	DE
Unitemp, Inc.	DE
Seaboard Mechanical Services, Inc.	DE
Eastern Landfill Gas, LLC
Oaks Landfill Gas, LLC
Distributed General Partners, LLC	DE
Rolling Hills Landfill Gas, LLC	DE
PES Home Services of Virginia	VA
Potomac Power Resources, LLC	DE
Fauquier Landfill Gas, LLC	DE
Trigen-Pepco Energy Services, LLC	DC
Pepco Government Services, LLC	DE
Pepco Enterprises, Inc.	DE
Electro Ecology, Inc.	NY
Potomac Capital Investment Corporation	DE
PCI Netherlands Corporation	NV
PCI Queensland Corporation	NV
Kramer Junction Company	CA
KJC Operating Company	CA
Luz Solar Partners, Ltd., III	CA
Luz Solar Partners, Ltd., IV	CA
Luz Solar Partners, Ltd., V	CA
Luz Solar Partners, Ltd., VI	CA
Luz Solar Partners, Ltd., VII	CA
Pepco Technologies, LLC	DE
AMP Funding, LLC	DE
RAMP Investments, LLC	DE
PCI Air Management Partners, LLC	DE
PCI Ever, Inc.	DE
Friendly Skies, Inc.	Virgin Islands
PCI Air Management Corporation	NV
American Energy Corporation	DE
PCI-BT Investing, LLC	DE
Potomac Aircraft Leasing Corporation	NV
Potomac Capital Markets Corporation	DE
Edison Place, LLC	DE
Linpro Harmans Land LTD Partnership	MD
Potomac Harmans Corporation	MD
Potomac Nevada Corporation	NV
Potomac Delaware Leasing Corporation	DE
Potomac Equipment Leasing Corporation	NV
Potomac Leasing Associates, LP	DE
Potomac Nevada Leasing Corporation	NV
PCI Engine Trading, Ltd.	Bermuda
Potomac Capital Joint Leasing Corporation	DE

405
_____________________________________________________________________________

PCI Nevada Investments	DE
PCI Holdings, Inc.	DE
Aircraft International Management Company	DE
PCI-BT Ventures	DE
Potomac Nevada Investment, Inc.	NV
Carbon Composite, LLC	DE
PCI Energy Corporation	DE
Pepco Communications, Inc.	DE
PHI Service Company	DE
Conectiv	DE
Delmarva Power & Light Company	DE & VA
Atlantic City Electric Company	NJ
Atlantic City Electric Company Transition Funding LLC	DE
Conemaugh Fuels, LLC	DE
Keystone Fuels, LLC	DE
Conectiv Properties and Investments, Inc.	DE
LUZ Solar Partners, LTD., IV	CA
DCTC-Burney, Inc.	DE
Forest Products, L.P.	DE
Burney Forest Products, A Joint Venture	CA
Conectiv Solutions LLC	DE
ATE Investments, Inc.	DE
King Street Assurance Ltd.	Bermuda
Enertech Capital Partners, L.P.	DE
Enertech Capital Partners II, L.P.	DE
Black Light Power, Inc.	DE
Millenium Account Services, LLC	DE
Conectiv Services, Inc.	DE
Conectiv Plumbing, L.L.C.	DE
Conectiv Thermal Systems, Inc.	DE
ATS Operating Services, Inc.	DE
Atlantic Jersey Thermal Systems, Inc.	DE
Thermal Energy Limited Partnership I	DE
Atlantic Generation, Inc.	NJ
Vineland Limited, Inc.	DE
Vineland Cogeneration L. P.	DE
Vineland General, Inc.	DE
Pedrick Gen., Inc.	NJ
Cogeneration Partners of America	NJ
Binghamton Limited, Inc.	DE
Binghamton General, Inc.	DE
Energy Investors Fund III, L.P.	DE
Conectiv Communications, Inc.	DE
Atlantic Southern Properties, Inc.	NJ
Conectiv Energy Holding Company	DE
ACE REIT, Inc	DE
Conectiv Atlantic Generation, L.L.C.	DE
Conectiv Bethlehem LLC	DE
Conectiv Delmarva Generation, Inc.	DE
Conectiv Pennsylvania Generation, LLC	DE
Conectiv Energy Supply, Inc.	DE
Conectiv Mid Merit, LLC	DE
Energy Systems North East, LLC	DE
Delaware Operating Services Company	DE
PHI Operating Services Company	DE
Tech Leaders II, L.P.	DE

406
_____________________________________________________________________________

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (Numbers 333-89938 and 333-104350) and the Registration Statements on Forms S-8 (Numbers 333-121823, 333-96673, 333-96675 and 333-96687) of Pepco Holdings, Inc. of our report dated March 16, 2005 relating to the financial statements, financial statement schedules, management's assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

PricewaterhouseCoopers LLP
Washington, DC
March 16, 2005

407
_____________________________________________________________________________

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-106209) of Potomac Electric Power Company of our report dated March 16, 2005 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

PricewaterhouseCoopers LLP
Washington, D.C.
March 16, 2005

408
_____________________________________________________________________________

Exhibit 23.3

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-115879) of Delmarva Power & Light Company of our report dated March 16, 2005 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

PricewaterhouseCoopers LLP
Washington, DC
March 16, 2005

409
_____________________________________________________________________________

Exhibit 23.4

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 Amendment #2 (No. 333-108861) of Atlantic City Electric Company of our report dated March 16, 2005 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

PricewaterhouseCoopers LLP
Washington, DC
March 16, 2005

410
_____________________________________________________________________________

Exhibit 31.1
CERTIFICATION
I, Dennis R. Wraase, certify that:
1.	I have reviewed this report on Form 10-K 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 Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b)	Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
	c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:  March 16, 2005			D. R. WRAASE                        Dennis R. Wraase Chairman of the Board, President   and Chief Executive Officer

411
_____________________________________________________________________________

Exhibit 31.2
CERTIFICATION
I, Joseph M. Rigby, certify that:
1.		I have reviewed this report on Form 10-K 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 Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b)		Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
	c)		Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d)		Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
	a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:  March 16, 2005				JOSEPH M. RIGBY                 Joseph M. Rigby Senior Vice President and   Chief Financial Officer

412
_____________________________________________________________________________

Exhibit 31.3
CERTIFICATION
I, Dennis R. Wraase, certify that:
1.		I have reviewed this report on Form 10-K 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 Exchanges 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 (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
	a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:  March 16, 2005				D. R. WRAASE                               Dennis R. Wraase Chairman of the Board and Chief Executive Officer

413
_____________________________________________________________________________

Exhibit 31.4
CERTIFICATION
I, Joseph M. Rigby, certify that:
1.	I have reviewed this report on Form 10-K 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 Exchanges 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 (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.		The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:  March 16, 2005				JOSEPH M. RIGBY                    Joseph M. Rigby Senior Vice President and   Chief Financial Officer

414
_____________________________________________________________________________

Exhibit 31.5
CERTIFICATION
I, Thomas S. Shaw, certify that:
1.	I have reviewed this report on Form 10-K 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 Exchanges 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 (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.		The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:  March 16, 2005				T. S. SHAW                            Thomas S. Shaw President and Chief Executive Officer

415
_____________________________________________________________________________

Exhibit 31.6
CERTIFICATION
I, Joseph M. Rigby, certify that:
1.	I have reviewed this report on Form 10-K 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 Exchanges 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 (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.		The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:  March 16, 2005				JOSEPH M. RIGBY                  Joseph M. Rigby Senior Vice President and   Chief Financial Officer

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Exhibit 31.7
CERTIFICATION
I, William J. Sim, certify that:
1.	I have reviewed this report on Form 10-K 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 Exchanges 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 (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.		The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:  March 16, 2005				W. J. SIM                            William J. Sim President and Chief Executive Officer

417
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Exhibit 31.8
CERTIFICATION
I, Joseph M. Rigby, certify that:
1.	I have reviewed this report on Form 10-K 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 Exchanges 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 (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.		The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:  March 16, 2005				JOSEPH M. RIGBY            Joseph M. Rigby Chief Financial Officer

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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 Report on Form 10-K of Pepco Holdings, Inc. for the year ended December 31, 2004, 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.
March 16, 2005	D. R. WRAASE                     Dennis R. Wraase President and Chief Executive Officer
March 16, 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.

419
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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 Report on Form 10-K of Potomac Electric Power Company for the year ended December 31, 2004, 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.
March 16, 2005	D. R. WRAASE                    Dennis R. Wraase Chairman of the Board and   Chief Executive Officer
March 16, 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.

420
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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 Report on Form 10-K of Delmarva Power & Light Company for the year ended December 31, 2004, 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.
March 16, 2005	T. S. SHAW                 Thomas S. Shaw Chief Executive Officer
March 16, 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.

421
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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 Report on Form 10-K of Atlantic City Electric Company for the year ended December 31, 2004, 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.
March 16, 2005	W. J. SIM                        William J. Sim President and Chief Executive Officer
March 16, 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.

422
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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.

March 16, 2005	PEPCO HOLDINGS, INC.   (Registrant) By     D. R. WRAASE                         Dennis R. Wraase         Chairman of the Board,           President and Chief           Executive Officer
March 16, 2005	POTOMAC ELECTRIC POWER COMPANY (Pepco)   (Registrant) By     D. R. WRAASE                         Dennis R. Wraase,         Chairman of the Board and           Chief Executive Officer
March 16, 2005	DELMARVA POWER & LIGHT COMPANY (DPL)     (Registrant) By      T. S. SHAW                         Thomas S. Shaw,         President and Chief           Executive Officer
March 16, 2005	ATLANTIC CITY ELECTRIC COMPANY (ACE)   (Registrant) By      W. J. SIM                         William J. Sim         President and Chief           Executive Officer

423
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     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the above named registrants and in the capacities and on the dates indicated:

D. R. WRAASE              Dennis R. Wraase	Chairman of the Board, President and Chief Executive Officer of Pepco Holdings, Chairman of the Board and Chief Executive Officer of Pepco and Director of Pepco Holdings, Pepco, DPL and ACE (Principal Executive Officer, Pepco Holdings and Pepco)	March 16, 2005
T. W. SHAW               Thomas S. Shaw	President and Chief Executive Officer of DPL and Director of Pepco, DPL and ACE (Principal Executive Officer of DPL)	March 16, 2005
W. J. WIM                 William J. Sim	President and Chief Executive Officer of ACE and Director of Pepco (Principal Executive Officer of ACE)	March 16, 2005
JOSEPH M. RIGBY           Joseph M. Rigby	Senior Vice President and Chief Financial Officer of Pepco Holdings, Pepco, and DPL, Chief Financial Officer of ACE and Director of Pepco, DPL and ACE (Principal Financial Officer of Pepco Holdings, Pepco, DPL and ACE)	March 16, 2005
JAMES P. LAVIN           James P. Lavin	Vice President and Controller of Pepco Holdings, Pepco and DPL and Controller of ACE (Principal Accounting Officer of Pepco Holdings, Pepco, DPL and ACE)	March 16, 2005

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Signature	Title	Date
EDMUND B. CRONIN, JR.      Edmund B. Cronin, Jr.	Director, Pepco Holdings	March 16, 2005
JACK B. DUNN               Jack B. Dunn, IV	Director, Pepco Holdings	March 16, 2005
Terence C. Golden	Director, Pepco Holdings.
GEORGE F. MacCORMACK       George F. MacCormack	Director, Pepco Holdings	March 16, 2005
RICHARD B. McGLYNN         Richard B. McGlynn	Director, Pepco Holdings	March 16, 2005
FLORETTA D. McKENZIE       Floretta D. McKenzie	Director, Pepco Holdings	March 16, 2005
LAWRENCE C. NUSSDORF       Lawrence C. Nussdorf	Director, Pepco Holdings	March 16, 2005
PETER F. O'MALLEY          Peter F. O'Malley	Director, Pepco Holdings	March 16, 2005
FRANK ROSS                 Frank K. Ross	Director, Pepco Holdings	March 16, 2005
PAULINE A. SCHNEIDER       Pauline A. Schneider	Director, Pepco Holdings	March 16, 2005
A. Thomas Young	Director, Pepco Holdings
WILLIAM T. TORGERSON       William T. Torgerson	Director of Pepco Holdings, Pepco, DPL and ACE	March 16, 2005

425
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INDEX TO EXHIBITS FILED HEREWITH
Exhibit No.	Registrant(s)	Description of Exhibit
3.1.1	Pepco	Restated Articles of Incorporation and Articles of Restatement of Pepco
10.56	PHI	Non-Management Director Compensation Arrangements
10.57	PHI	Form of Election regarding Non-Management Directors Compensation Plan
10.58	PHI	PHI Named Executive Officer 2005 Compensation Determinations
10.59	Pepco	Pepco Named Executive Officer 2005 Compensation Determinations
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
21	PHI Pepco DPL ACE	Subsidiaries of the Registrant
23.1	PHI	Consent of Independent Registered Public Accounting Firm
23.2	Pepco	Consent of Independent Registered Public Accounting Firm
23.3	DPL	Consent of Independent Registered Public Accounting Firm
23.4	ACE	Consent of Independent Registered Public Accounting Firm
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
99.1	PHI	Unaudited Financial Statements of Starpower, LLC

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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