Delmarva Power & Light 10-K 2006 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, 2006
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:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Pepco Holdings	Yes   X	No	Pepco	Yes	No   X
DPL	Yes	No   X	ACE	Yes	No   X

     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Pepco Holdings		Pepco	X
DPL	X	ACE	X

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

Pepco Holdings	Yes   X	No	Pepco	Yes	No   X
DPL	Yes	No   X	ACE	Yes	No   X

     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 only).   .

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of "accelerated filer and larger accelerated filer" in Rule 12b-2 of the Exchange Act.

	Large Accelerated Filer	Accelerated Filer	Non-Accelerated Filer
Pepco Holdings	X
Pepco			X
DPL			X
ACE			X

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

Pepco Holdings	Yes	No   X	Pepco	Yes	No   X
DPL	Yes	No   X	ACE	Yes	No   X

     Pepco, DPL, and ACE meet the conditions set forth in General Instruction 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.

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Registrant	Aggregate Market Value of Voting and Non-Voting Common Equity Held by Non-Affiliates of the Registrant at June 30, 2006	Number of Shares of Common Stock of the RegistrantOutstanding at February 1, 2007
Pepco Holdings	$4.5 billion	192,458,100 ($.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 2007 Annual Meeting of Shareholders to be filed with the Securities and Exchange Commission on or about March 29, 2007 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 1A.	-	Risk Factors	19
Item 1B.	-	Unresolved Staff Comments	29
Item 2.	-	Properties	30
Item 3.	-	Legal Proceedings	31
Item 4.	-	Submission of Matters to a Vote of Security Holders	36
PART II
Item 5.	-	Market for Registrant's Common Equity, Related    Stockholder Matters and Issuer Purchases of    Equity Securities	36
Item 6.	-	Selected Financial Data	39
Item 7.	-	Management's Discussion and Analysis of    Financial Condition and Results of Operations	41
Item 7A.	-	Quantitative and Qualitative Disclosures    About Market Risk	133
Item 8.	-	Financial Statements and Supplementary Data	137
Item 9.	-	Changes in and Disagreements With Accountants    on Accounting and Financial Disclosure	330
Item 9A.	-	Controls and Procedures	330
Item 9B.	-	Other Information	332
PART III
Item 10.	-	Directors, Executive Officers and Corporate Governance	332
Item 11.	-	Executive Compensation	334
Item 12.	-	Security Ownership of Certain Beneficial Owners and    Management and Related Stockholder Matters	335
Item 13.	-	Certain Relationships and Related Transactions, and    Director Independence	336
Item 14.	-	Principal Accounting Fees and Services	336
PART IV
Item 15.	-	Exhibits, Financial Statement Schedules	337
Financial Statements		Included in Part II, Item 8
Schedule I                    -		Condensed Financial Information of Parent Company	338
Schedule II                  -		Valuation and Qualifying Accounts	341
Exhibit 12                    -		Statements Re: Computation of Ratios	357
Exhibit 21                    -		Subsidiaries of the Registrant	361
Exhibit 23                    -		Consents of Independent Registered Public Accounting Firm	363
Exhibits 31.1 - 31.8		Rule 13a-14a/15d-14(a) Certifications	367
Exhibits 32.1 - 32.4		Section 1350 Certifications	375
Signatures			379
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	GLOSSARY OF TERMS
Term	Definition
2006 Supply Agreement	A supply agreement between Conectiv Energy and DPL covering the period June 1, 2006, though May 31, 2007, pursuant to which DPL currently obtains all of the energy and capacity needed to fulfill its Default Service obligations in Virginia
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
ACO	Administrative Consent Order
ADFIT	Accumulated deferred federal income taxes
ADITC	Accumulated deferred investment tax credits
AFUDC	Allowance for Funds Used During Construction
Ancillary services	Generally, electricity generation reserves and reliability services
APB	Accounting Principles Board
APCA	Air Pollution Control Act
Appellate Division	Appellate Division of the Superior Court of New Jersey
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
Bankruptcy Funds	$13.25 million in funds from the Bankruptcy Settlement
Bankruptcy Settlement	The bankruptcy settlement among the parties concerning the environmental proceedings at the Metal Bank/Cottman Avenue site
Bcf	Billion cubic feet
BGS	Basic Generation Service (the supply of electricity by ACE to retail customers in New Jersey who have not elected to purchase electricity from a competitive supplier)
BGS-FP	BGS-Fixed Price service
BGS-CIEP	BGS-Commercial and Industrial Energy Price service
Bondable Transition   Property	Right to collect a non-bypassable transition bond charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU
BSA	Bill Stabilization Adjustment
CAA	Federal Clean Air Act
CAIR	EPA's Clean Air Interstate rule
CAMR	EPA's Clean Air Mercury rule
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
CO2	Carbon dioxide
Conectiv	A wholly owned subsidiary of PHI which is a holding company under PUHCA 2005 and the parent of DPL and ACE
Conectiv Energy	Conectiv Energy Holding Company and its subsidiaries
Conectiv Group	Conectiv and certain of its subsidiaries that were involved in a like-kind exchange transaction under examination by the IRS
Cooling Degree Days	Daily difference in degrees by which the mean (high and low divided by 2) dry bulb temperature is above a base of 65 degrees Fahrenheit
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Term	Definition
CRMC	PHI's Corporate Risk Management Committee
CWA	Federal Clean Water Act
DCPSC	District of Columbia Public Service Commission
Default Electricity   Supply	The supply of electricity by PHI's electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as Default Service, SOS, BGS, or POLR service
Default Service	The supply of electricity by DPL in Virginia to retail customers who have not elected to purchase electricity from a competitive supplier
Default Supply Revenue	Revenue received for Default Electricity Supply
Delaware District Court	United States District Court for the District of Delaware
Directors Compensation   Plan	PHI Non-Management Directors Compensation Plan
District Court	United States District Court for the Northern District of Texas
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
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
FAS	Financial Accounting Standards
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fifth Circuit	U.S. Court of Appeals for the Fifth Circuit
FIN	FASB Interpretation Number
Financing Order	Financing Order of the SEC under PUHCA 1935 dated June 30, 2005, with respect to PHI and its subsidiaries
FSP	FASB Staff Position
FSP AUG AIR-1	FSP American Institute of Certified Public Accountants Industry Audit Guide, Audits of Airlines--"Accounting for Planned Major Maintenance Activities"
FTB	FASB Technical Bulletin
Full Requirements   Load Service	The supply of energy by Conectiv Energy to utilities to fulfill their Default Electricity Supply obligations
GAAP	Accounting principles generally accepted in the United States of America
GCR	Gas Cost Recovery
GPC	Generation Procurement Credit
Gwh	Gigawatt hour
Heating Degree Days	Daily difference in degrees by which the mean (high and low divided by 2) dry bulb temperature is below a base of 65 degrees Fahrenheit.
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Term	Definition
HPS	Hourly Priced Service DPL is obligated to provide to its largest customers
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
LTIP	Pepco Holdings' Long-Term Incentive Plan
Mcf	One thousand cubic feet
MDE	Maryland Department of the Environment
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
MGP	Manufactured gas plant
Mirant	Mirant Corporation, its predecessors and its subsidiaries, and the Mirant business that emerged from bankruptcy on January 3, 2006 pursuant to the Reorganization Plan, as a new corporation of the same name
MOA	Memorandum of agreement entered into by DPL, the staff of the VSCC and the Virginia Attorney General's office in the docket approving DPL's generating asset divestiture in 2000
MPSC	Maryland Public Service Commission
NFA	No Further Action letter issued by the NJDEP
NJBPU	New Jersey Board of Public Utilities
NJDEP	New Jersey Department of Environmental Protection
NJPDES	New Jersey Pollutant Discharge Elimination System
NOPR	Notice of Proposed Rulemaking
Normalization   provisions	Sections of the IRC 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
Notice	Notice 2005-13 issued by the Treasury Department and IRS on February 11, 2005
NOx	Nitrogen oxide
NPDES	National Pollutant Discharge Elimination System
NSR	New Source Review
NUGs	Non-utility generators
OCI	Other Comprehensive Income
Panda	Panda-Brandywine, L.P.
Panda PPA	PPA between Pepco and Panda
PARS	Performance Accelerated Restricted Stock
PBO	Projected benefit obligation
PCI	Potomac Capital Investment Corporation and its subsidiaries
Pepco	Potomac Electric Power Company
Pepco Distribution	The total aggregate distribution to Pepco pursuant to the Settlement Agreement
Pepco Energy Services	Pepco Energy Services, Inc. and its subsidiaries
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Term	Definition
Pepco Holdings or PHI	Pepco Holdings, Inc.
Pepco TPA Claim	Pepco's $105 million allowed, pre-petition general unsecured claim against Mirant
PHI Parties	The PHI Retirement Plan, PHI and Conectiv, parties to cash balance plan litigation brought by three management employees of PHI Service Company
PHI Retirement Plan	PHI's noncontributory retirement plan
PJM	PJM Interconnection, LLC
PLR	Private letter ruling from the IRS
POLR	Provider of Last Resort service (the supply of electricity by DPL before May 1, 2006 to retail customers in Delaware who did not elect to purchase electricity from a competitive supplier)
POM	Pepco Holdings' NYSE trading symbol
Power Delivery	PHI's Power Delivery Business
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 Panda PPA
PRP	Potentially responsible party
PSD	Prevention of Significant Deterioration
PUHCA 1935	Public Utility Holding Company Act of 1935, which was repealed effective February 8, 2006
PUHCA 2005	Public Utility Holding Company Act of 2005, which became effective February 8, 2006
RAR	IRS revenue agent's report
RARM	Reasonable Allowance for Retail Margin
RC Cape May	RC Cape May Holdings, LLC, an affiliate of Rockland Capital Energy Investments, LLC, and the purchaser of the B.L. England generating facility
Recoverable stranded   costs	The portion of stranded costs that is recoverable from ratepayers as approved by regulatory authorities
Regulated T&D Electric   Revenue	Revenue from the transmission and the delivery of electricity to PHI's customers within its service territories at regulated rates
Reorganization Plan	Mirant's Plan of Reorganization
RGGI	Regional Greenhouse Gas Initiative
RI/FS	Remedial Investigation/Feasibility Study
ROE	Return on equity
SAB	SEC Staff Accounting Bulletin
SEC	Securities and Exchange Commission
Second Circuit	United States Court of Appeals for the Second Circuit
Settlement Agreement	Settlement Agreement and Release, dated as of May 30, 2006 between Pepco and Mirant
SFAS	Statement of Financial Accounting Standards
SMECO	Southern Maryland Electric Cooperative, Inc.
SMECO Agreement	Capacity purchase agreement between Pepco and SMECO
SMECO Settlement   Agreement	Settlement Agreement and Release entered into between Mirant and SMECO
SO2	Sulfur dioxide
iv _____________________________________________________________________________________
Term	Definition
SOS	Standard Offer Service (the supply of electricity by Pepco in the District of Columbia, by Pepco and DPL in Maryland and by DPL in Delaware on and after May 1, 2006, to retail customers who have not elected to purchase electricity from a competitive supplier)
Standard Offer Service   revenue or SOS revenue	Revenue Pepco and DPL, respectively, receive for the procurement of energy for its SOS customers
Starpower	Starpower Communications, LLC
Stranded costs	Costs incurred by a utility in connection with providing service which would 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.
Third Circuit	United States Court of Appeals for the Third Circuit
Tolling agreement	A physical or financial contract where one party delivers fuel to a specific generating station in exchange for the power output
TPA	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
Utility PRPs	A group of utility PRPs including Pepco that are parties to a settlement involving the environmental proceedings at the Metal Bank/Cottman Avenue site
VaR	Value at Risk
Virginia Restructuring Act	Virginia Electric Utility Restructuring Act
VSCC	Virginia State Corporation Commission
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Item 1.    BUSINESS

OVERVIEW

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

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

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

     PHI was incorporated in Delaware in 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 the combination of DPL and ACE. The following chart shows, in simplified form, the corporate structure of PHI and its principal subsidiaries.

     In 2006, the Public Utility Holding Company Act of 1935 (PUHCA 1935) was repealed and was replaced by the Public Utility Holding Company Act of 2005 (PUHCA 2005). As a result, PHI has ceased to be regulated by the Securities and Exchange Commission (SEC) as a public utility holding company and is now subject to the regulatory oversight of the Federal Energy Regulatory Commission (FERC). PHI has notified FERC that it will continue, until further notice, to operate pursuant to the financing order issued by the SEC under PUHCA 1935, which has an authorization period ending June 30, 2008 (the Financing Order), relating to the issuance of securities and guarantees, other financing transactions and the operation of the money pool by PHI and its subsidiaries that participate in the money pool. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- PUHCA 2005 Restrictions" for additional information.

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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 to PHI and its operating subsidiaries. These services are provided pursuant to a service agreement among PHI, PHI Service Company, and the participating operating subsidiaries. The expenses of the service company are charged to PHI and the participating operating subsidiaries in accordance with costing methodologies 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. Each of Pepco, DPL and ACE has one operating segment.

Investor Information

     Each of PHI, Pepco, DPL and ACE files reports under the Securities Exchange Act of 1934, as amended. The Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports, of each of the companies 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 athttp://www.pepcoholdings.com/investors.

     The following is a description of each of PHI's two principal business operations.

Power Delivery

     The largest component of PHI's business is Power Delivery, which consists of the transmission and distribution of electricity and the distribution of natural gas. In 2006, 2005 and 2004, respectively, PHI's Power Delivery operations produced 61%, 58% and 61% of PHI's consolidated operating revenues (including revenue from intercompany transactions) and 67%, 74% and 70% of PHI's consolidated operating income (including income from intercompany transactions).

     PHI's Power Delivery business is conducted by its three regulated utility subsidiaries: Pepco, DPL and ACE. Each subsidiary is a regulated public utility in the jurisdictions that comprise its service territory. 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 carry electricity to end-use customers in the utility's service territory.

Delivery of Electricity and Natural Gas and Default Electricity Supply

     Each company is responsible for the delivery of electricity and, in the case of DPL, natural gas in its service territory, for which it is paid tariff rates established by the local public service commission. Each company also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service varies by jurisdiction as follows:

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

     In this Form 10-K, these supply service obligations are referred to generally as Default Electricity Supply.

     In the aggregate, the Power Delivery business delivers electricity to more than 1.8 million customers in the mid-Atlantic region and distributes natural gas to approximately 121,000 customers in Delaware.

     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 eastern United States. FERC has designated a number of regional transmission organizations to coordinate the operation and planning of portions of the interstate transmission grid. Pepco, DPL and ACE are members of the PJM Regional Transmission Organization. PJM Interconnection, LLC (PJM) provides transmission planning functions and acts as the independent system operator for the PJM Regional Transmission Organization. In this capacity, PJM coordinates the movement of electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. FERC has designated PJM as the sole provider of transmission s ervice in the PJM region. Any entity that wishes to have electricity delivered at any point in the PJM region must obtain transmission services from PJM at rates approved by FERC. In accordance with FERC rules, Pepco, DPL, ACE and the other transmission-owning 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 transmission owners fees approved by FERC.

     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 supply 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, legislative and regulatory actions in 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 be responsible for the distribution of electricity in their respective service territories, as the result of deregulation, customers in those service territories now are permitted to choo se their electricity supplier from among a number of non-regulated, competitive suppliers. Customers who do not choose a competitive supplier receive Default Electricity Supply 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

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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 higher in the summer months associated with cooling and demand for electricity and natural gas is generally higher in the winter months associated with heating, as compared to other times of the year. 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's electricity delivery operations 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's electricity delivery operations 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's natural gas distribution operations in Delaware are regulated by the DPSC. ACE's electric delivery operations are regulated 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 640 square miles and has a population of 2.1 million. As of December 31, 2006, Pepco delivered electricity to 753,000 customers (of which 240,960 were located in the District of Columbia and 512,040 were located in Maryland), as compared to 747,000 customers as of December 31, 2005 (of which 239,040 were located in the District of Columbia and 507,960 were located in Maryland).

     In 2006, Pepco delivered a total of 26,488,000 megawatt hours of electricity, of which 29% was delivered to residential customers, 51% to commercial customers, and 20% to United States and District of Columbia government customers. In 2005, Pepco delivered 27,594,000 megawatt hours of electricity, of which 30% was delivered to residential customers, 51% to commercial customers, and 19% to United States and District of Columbia government customers.

     Pepco has been providing SOS in Maryland since July 2004. Pursuant to an order issued by the MPSC in November 2006, Pepco will continue to be obligated to provide SOS to residential and small commercial customers indefinitely, until further action of the Maryland General Assembly, and to medium-sized commercial customers through May 2009. Pepco also has an ongoing obligation to provide SOS service at hourly priced rates to the largest customers. Pepco

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purchases the power supply required to satisfy its SOS obligation from wholesale suppliers under contracts entered into pursuant to competitive bid procedures approved and supervised by the MPSC. Pepco is entitled to recover from its SOS customers the cost of the SOS supply plus an average margin of $.002 per kilowatt hour (calculated at the time of the announcement of the contracts, based on total sales to residential and 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 depends on the number of Maryland SOS 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 SOS customers and customers in Maryland who have selected another energy supplier. These delivery rates are capped through December 31, 2006 pursuant to the MPSC order issued in connection with the Pepco acquisition of Conectiv, but are subject to adjustment if FERC transmission rates increase by more than 10%.

     Pepco has been providing SOS in the District of Columbia since February 2005. Pursuant to orders issued by the DCPSC, Pepco will continue to be obligated to provide SOS for small commercial and residential customers through May 2011 and for large commercial customers through May 2009. Pepco purchases the power supply required to satisfy its SOS obligation from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved by the DCPSC. Pepco is entitled to recover from its SOS customers the costs associated with the acquisition of the SOS supply plus administrative charges that are intended to allow Pepco to recover the administrative costs incurred to provide the SOS. These administrative charges include an average margin for Pepco of $.00248 per kilowatt hour (calculated at the time of the announcement of the contracts, based on total sales to residential and small and large commercial District of Columbia 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 depends on the number of District of Columbia SOS 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 SOS customers and customers in the District of Columbia who have selected another energy supplier. Delivery rates in the District of Columbia generally are capped through July 2007, but are subject to adjustment if FERC transmission rates increase by more than 10%, except that for residential low-income customers, rates generally are capped through July 2009.

     For the year ended December 31, 2006, 60% of Pepco's Maryland sales (measured by megawatt hours) were to SOS customers, as compared to 62% in 2005 and in 2006 57% of its District of Columbia sales were to SOS customers, as compared to 41% in 2005.

     DPL

     DPL is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and Virginia and provides natural gas 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 corporation in 1979. DPL's electricity distribution service territory covers 6,000 square miles and has a population of 1.3 million. DPL's natural gas distribution service territory covers 275 square miles and has a population of 523,000. As of December 31, 2006, DPL delivered electricity to 513,000 customers (of which 295,000 were located in Delaware, 196,000 were located in Maryland, and 22,000 were located i n Virginia) and delivered natural

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gas to 121,000 customers (all of which were located in Delaware), as compared to 510,000 electricity customers as of December 31, 2005 (of which 292,000 were located in Delaware, 196,000 were located in Maryland, and 22,000 were located in Virginia) and 120,000 natural gas customers.

     In 2006, DPL delivered a total of 13,477,000 megawatt hours of electricity to its customers, of which 38% was delivered to residential customers, 40% to commercial customers and 22% to industrial customers. In 2005, DPL delivered a total of 14,101,000 megawatt hours of electricity, of which 40% was delivered to residential customers, 38% to commercial customers and 22% to industrial customers.

     In 2006, DPL delivered 18,300,000 Mcf (one thousand cubic feet) of natural gas to retail customers in its Delaware service territory, of which 36% of DPL's retail gas deliveries were sales to residential customers, 25% to commercial customers, 4% to industrial customers, and 35% to customers receiving a transportation-only service. In 2005, DPL delivered 20,700,000 Mcf of natural gas, of which 41% of DPL's retail gas deliveries were sales to residential customers, 27% were sales to commercial customers, 5% were to industrial customers, and 27% were sales to customers receiving a transportation-only service.

     DPL has been providing Default Electricity Supply in Delaware since May 2006. Pursuant to orders issued by the DPSC, DPL will continue to be obligated to provide fixed-price SOS to residential, small commercial and industrial customers through May 2009 and to medium, large and general service customers through May 2008. DPL purchases the power supply required to satisfy its fixed-price SOS obligation from wholesale suppliers under contracts entered into pursuant to competitive bid procedures approved by the DPSC. DPL also has an obligation to provide Hourly Priced Service (HPS) for the largest customers. Power to supply the HPS customers is acquired on next-day and other short-term PJM markets. DPL's rates for supplying fixed-price SOS and HPS reflect the associated capacity, energy, transmission, and ancillary services costs and a Reasonable Allowance for Retail Margin (RARM). Components of the RARM include a fixed annual margin of $2.75 million, plus estimated increme ntal expenses, a cash working capital allowance, and recovery with a return over five years of the capitalized costs of the billing system used for billing HPS customers. DPL is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both SOS customers and customers in Delaware who have selected another energy supplier.

     In Delaware, DPL sales to Default Electricity Supply customers represented 69% of total sales (measured by megawatt hours) for the year ended December 31, 2006, as compared to 90% in 2005.

     DPL has been providing SOS in Maryland since June 2004. Pursuant to an order issued bythe MPSC in November 2006, DPL will continue to be obligated to provide SOS to residential and small commercial customers indefinitely, until further action of the Maryland General Assembly, and to medium-sized commercial customers through May 2009. DPLpurchases the power supply required to satisfy its market rateSOS obligation from wholesale suppliers under contracts entered into pursuant to competitive bid procedures approved and supervised by the MPSC. DPL is entitled to recover from itsSOS customers the costsof theSOS supplyplus an average margin of $.002 per ki lowatt hour (calculated at the time of the announcement of the contracts, based on total sales to residential and 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 depends on the number of Maryland SOS customers from each customer class and the load taken by such customers over

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the time period. DPL is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both SOS customers and customers in Maryland who have selected another energy supplier.

     In Maryland, DPL sales to SOS customers represented 75% of total sales (measured by megawatt hours) for the year ended December 31, 2006, as compared to 78% in 2005.

     DPL has been providing Default Service in Virginia since March 2004, and under the terms of the Virginia Electric Utility Restructuring Act (the Virginia Restructuring Act), DPL is obligated to continue to offer Default Service to customers in Virginia until relieved of that obligation by the VSCC; however, amendments to the Virginia Restructuring Act that alter this obligation have been passed, as described below. 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 covering the period June 1, 2006, though May 31, 2007 (the 2006 Supply Agreement). The 2006 Supply Agreement was awarded to Conectiv Energy through a competitive bid procedure supervised by the VSCC in which Conectiv Energy was the low bidder. DPL's approved rates for Default Service allow it to recover costs related to the purchase of power in accordance with a proxy rate calculation, which is an a pproximation of what the cost of power would have been if DPL had not divested its generating units. The proxy rate calculation, which has the effect of operating as a cap on recoverable purchased power costs, is a component of a memorandum of agreement entered into by DPL, the staff of the VSCC and the Virginia Attorney General's office in the docket approving DPL's generating asset divestiture in 2000 (the MOA), and was a condition of that divestiture.

     On March 10, 2006, DPL filed for a rate increase with the VSCC for its Virginia Default Service customers to take effect on June 1, 2006, which was intended to allow DPL to recover its higher cost for energy established by the competitive bid procedure. On June 19, 2006, the VSCC issued an order that granted a rate increase for DPL of $11.5 million ($8.5 million less than requested by DPL in its March 2006 filing), to go into effect July 1, 2006. In determining the amount of the approved increase, the VSCC applied the proxy rate calculation to DPL's fuel factor, rather than allowing full recovery of the costs DPL incurred in procuring the supply necessary for its Default Service obligation. The estimated after-tax earnings and cash flow impacts of the decision are reductions of approximately $3.6 million in 2006 (including the loss of revenue in June 2006 associated with the Default Service rate increase being deferred from June 1 until July 1) and $2.0 million i n 2007. The order also mandated that DPL file an application by March 1, 2007 (which has been delayed until April 2, 2007 by subsequent VSCC order) for Default Service rates to become effective June 1, 2007, which should include a calculation of the fuel factor that is consistent with the procedures set forth in the order.

     In February 2007, the Virginia General Assembly passed amendments to the Virginia Restructuring Act that modified the method by which investor-owned electric utilities in Virginia will be regulated by the VSCC. These amendments to the Virginia Restructuring Act, subject to further amendment or veto by the Virginia governor and subsequent action by the General Assembly, will be effective on July 1, 2007. The amendments provide that, as of December 31, 2008, the following will come to an end: (i) capped rates (the previous expiration date was December 31, 2010); (ii) DPL's Default Service obligation; and (iii) customer choice, except that customers with loads of 5 megawatts or greater will continue to be able to buy from competitive suppliers, as will smaller non-residential customers that aggregate their loads to reach the 5 megawatt threshold and obtain VSCC approval. Additionally, if an ex-customer of Default Service wants to return to DPL as its energy supplier, it must give 5 years notice or obtain approval of the VSCC that the return is in the public interest. In this event, the ex-

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customer must take DPL's service at market based rates. DPL also believes that the amendments to the Virginia Restructuring Act will terminate, as of December 31, 2008, the ratemaking provisions within the MOA, including the application of the proxy rate calculation to DPL's fuel factor as discussed above; however, the VSCC's interpretation of these provisions is not known. It should be noted that in DPL's view, in the absence these amendments, the MOA and all of its provisions (including the proxy rate calculation) expire on July 1, 2007; the VSCC staff and the Virginia Attorney General disagree with DPL's position. Assuming the ratemaking provisions of the MOA end on December 31, 2008 pursuant to the amended Virginia Restructuring Act, the amendments provide that DPL shall file a rate case in 2009 and every 2 years thereafter. The ROE to be allowed by the VSCC will be set within a range, the lower of which is essentially the average of vertically integrated investor-owned electric utilities in the s outheast with an upper point that is 300 basis points above that average. The VSCC has authority to set rates higher or lower to allow DPL to maintain the opportunity to earn the determined ROE and to credit back to customers, in whole or in part, earnings that were 50 basis points or more in excess of the determined ROE. The amended Virginia Restructuring Act includes various incentive ROEs for the construction of new generation and would allow the VSCC to penalize or reward DPL for efficient operations or, if DPL were to add new generation, for generating unit performance. There are also enhanced ratemaking features if DPL pursues conservation, demand management and energy efficiency programs or pursues renewable energy portfolios.

     DPL is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both 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 apply for two changes in delivery rates (one prior to July 1, 2007 and another between July 1, 2007 and December 31, 2010).

     In Virginia, DPL sales to Default Service customers represented 94% of total sales (measured by megawatt hours) in 2006 and 100% of total sales in 2005.

     DPL also provides regulated natural gas supply and distribution service to customers in its Delaware natural gas service territory. Large and medium volume commercial and industrial natural gas customers may purchase natural gas either from DPL or from other suppliers. DPL uses its natural gas distribution facilities to transport natural gas 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 for resale to its sales service customers from marketers and producers through a combination of long-term agreements and next-day delivery arrangements. For the twelve months ended December 31, 2006, DPL supplied 66% of the natural gas that it delivered, compared to 73% in 2005.

     ACE

     ACE is primarily engaged in the transmission and distribution of electricity in a service territory consisting of 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 2,700 square miles and has a population of 1 million. As of December 31, 2006, ACE delivered electricity to 539,000 customers in its service territory, as compared to 532,000 customers as of December 31, 2005. In 2006, ACE delivered a total of9,931,000 megawatt hours of electricity to its customers, of which 43% was delivered to residential customers, 44% to commercial customers and 13% to industrial customers. In 2005, ACE delivered10,080,000 megawatt hours of electricity to its customers, of which44% was

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delivered to residential customers,43% to commercial customers, and13% to industrial customers.

     Electric customers in New Jersey who do not choose another supplier receive BGS from their electric distribution company. New Jersey's electric distribution companies, including ACE, jointly procure the supply to meet their BGS obligations from competitive suppliers selected through auctions authorized by the NJBPU for New Jersey's total BGS requirements. The winning bidders in the auction are required to supply a specified portion of the BGS customer load with full requirements service, consisting of power supply and transmission service.

     ACE provides two types of BGS:

· BGS-Fixed Price (BGS-FP), which is supplied to smaller commercial and residential customers at seasonally-adjusted fixed prices. BGS-FP rates change annually on June 1 and are based on the average BGS price obtained at auction in the current year and the two prior years. ACE's BGS-FP load is approximately 2,100 megawatts, which represents approximately 87% of ACE's total BGS load. Approximately one-third of this total load is auctioned off each year for a three-year term.

· BGS-Commercial and Industrial Energy Price (BGS-CIEP), which is supplied to larger customers at hourly PJM real-time market prices for a term of 12 months. ACE's BGS-CIEP load is approximately 315 megawatts, which represents approximately 13% of ACE's BGS load. This total load is auctioned off each year for a one-year term.

     As of December 31, 2006, Conectiv Energy supplied one 100 megawatt block of ACE's BGS-FP load.

     ACE is paid tariff rates established by the NJBPU that compensate it for the cost of obtaining the BGS from competitive suppliers. ACE does not make any profit or incur any loss on the supply component of the BGS it provides to customers.

     ACE is paid tariff delivery rates for the delivery of electricity over its transmission and distribution facilities to both BGS customers and customers in its service territory who have selected another energy supplier.

     ACE sales to New Jersey BGS customers represented 78% of total sales (measured by megawatt hours) for the year ended December 31, 2006 and 2005.

     In addition to its electricity transmission and distribution operations, as of December 31, 2005, ACE owned a 2.47% undivided interest in the Keystone electric generating facility and a 3.83% undivided interest in the Conemaugh electric generating facility (with a combined generating capacity of 108 megawatts) and the B.L. England electric generating facility (with a generating capacity of 447 megawatts).

     On September 1, 2006, ACE sold its 2.4% undivided interest in the Keystone generating facility and its 3.83% undivided interest in the Conemaugh generating facility to Duquesne Light Holdings Inc. for approximately $177.0 million, which was subsequently decreased by $1.6 million based on a post-closing 60-day true-up for applicable items not known at the time of the closing. Approximately $81.3 million of the net gain from the sale has been used to offset the remaining regulatory asset balance, which ACE has been recovering in rates, and approximately $49.8 million of the net gain is being returned to ratepayers over a 33-month period as a credit

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on their bills, which began during the October 2006 billing period. The balance to be repaid to customers is $48.4 million as of December 31, 2006.

     On February 8, 2007, ACE sold the B.L. England generating facility (with a generating capacity of 447 megawatts) to RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy Investments, LLC, for a price of $9.0 million, after adjustment for, among other things, variances in the value of fuel and material inventories at the time of closing, certain capital expenditures, plant operating capacity, the value of certain benefits for transferred employees and the actual closing date. The purchase price will be further adjusted based on a post-closing 60-day true-up for applicable items not known at the time of the closing. In addition, RC Cape May and ACE have agreed to arbitration concerning whether RC Cape May must pay to ACE, as part of the purchase price, an additional $3.1 million remaining in dispute. The sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized. ACE anticipates that approx imately $9 million to $10 million of additional assets related to B.L. England may, subject to NJBPU approval, be eligible for recovery as stranded costs. For the year ended December 31, 2006, B.L. England's operating revenue was $86.9 million.

     ACE also has several contracts with non-utility generators (NUGs) under which ACE purchased 3.8 million megawatt hours of power in 2006. ACE sells the electricity purchased under the contracts with NUGs into the wholesale market administered by PJM.

     During 2006, ACE's generation and wholesale electricity sales operations produced approximately 26% of ACE's operating revenue, of which approximately 32% was produced by the B.L. England, Keystone and Conemaugh facilities.

     In 2001, ACE established Atlantic City Electric Transition Funding LLC (ACE Funding) solely for the purpose of securitizing authorized portions of ACE's recoverable stranded costs through the issuance and sale of bonds (Transition Bonds). The proceeds of the sale of each series of Transition Bonds have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable transition bond charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond charges collected from ACE's customers, are not available to creditors of ACE. The holders of Transition Bonds have recourse only to the assets of ACE Funding.

Competitive Energy

     PHI's Competitive Energy business is engaged in the generation of electricity and the non-regulated marketing and supply of electricity andnaturalgas, and related energy management services, primarily in the mid-Atlantic region. In2006, 2005 and 2004 PHI's Competitive Energy operations produced 46%, 51%and 50%, respectively, of PHI's consolidated operating revenues. In 2006, 2005 and 2004 PHI's Competitive Energy operations produced 20%, 16% and 19%, respectively, of PHI's consolidated operating income.PHI's Competitive Energy operations are conducted by Conectiv Energy and Pepco Energy Services. For financial reporting purposes Conectiv Energy and Pepco Energy Services each is treated as a separate segment.

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     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 and short-term bilateral contracts. Conectiv Energy also supplies electric power to satisfy a portion of ACE's New Jersey, DPL's Delaware, Maryland, and Virginia and Pepco's Maryland Default Electricity Supply load, as well as default electricity supply load shares of other utilities. PHI refers to these activities as Merchant Generation & Load Service. Other than itsdefault electricity supply sales, Conectiv Energy does not participate in the retail competitive power supply market. Conectiv Energy obtains the electricity required to meet its power supply obligations from its owngenerating plants, under bilateralcontracts entered into with other wholesale market participantsand from purchases in the wholesale market administered by PJM.

     Conectiv Energy's generation capacity is concentrated in mid-merit plants, which due to their operating flexibility and multi-fuel capability 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 more frequently and for longer periods of time than peak-load plants because of better heat rates. As of December 31, 2006, Conectiv Energy owned and operated mid-merit plants with a combined 2,713 megawatts of capacity, peak-load plants with a combined 639 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 tur bines to a third party based upon market demand.

     Conectiv Energy also sells natural gas and fuel oil to very large end-users and to wholesale market participants under bilateral agreements and operates a real-time power desk, which generates margin by identifying and capturing price differences between power pools and locational and timing differences within a power pool. 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- and short-term bilateral contracts with other market participants.

     Conectiv Energy actively engages in commodity risk management activities to reduce its financial exposure to changes in the value of its assets and obligations due to commodity price fluctuations. A portion of these risk management activities is 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: (1) 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 (2) to manage the cost of fulfilling its contracts to supply load in order to ensure stable and known minimum cash flows and lock-in favorable prices and margins when they become available. To a lesser extent, Conectiv Energy also operates a r eal-time power desk, which generates margin by capturing price differences between power pools, and locational and timing differences within a power pool.

     Conectiv Energy's goal is to manage the risk associated with the expected power output of its generation facilities and their fuel requirements. The risk management goals are approved by PHI's Corporate Risk Management Committee and may change from time to time based on

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market conditions. The actual level of coverage may vary depending on the extent to which Conectiv Energy is successful in implementing its risk management strategies. For additional discussion of Conectiv Energy's risk management activities, see Item 7A "Quantitative and Qualitative Disclosures About Market Risk."

     Pepco Energy Services

    Pepco Energy Services provides retail energy supply and energy services primarily to commercial, industrial, and government customers. Pepco Energy Services sells electricity, including electricity from renewable resources, to customers located in the mid-Atlantic and northeastern regions of the U.S. and the Chicago, Illinois area. As of December 31, 2006, Pepco Energy Services' estimated retail electricity backlog is 31.3 million MWH for delivery through 2011, an increase of 105% since December 31, 2005. Pepco Energy Services also sells natural gas to customers primarily located in the mid-Atlantic region.

     Pepco Energy Services owns and operates district energy systems in Atlantic City, New Jersey and Wilmington, Delaware and sells steam and chilled water to customers in those cities. Pepco Energy Services also provides energy savings performance contracting services principally to federal, state and local government customers, and designs, constructs, and operates combined heat and power plants and central energy plants.

     Pepco Energy Services provides high voltage construction and maintenance services to utilities throughout the United States and low voltage electric and telecommunication construction and maintenance services in the Washington, D.C. area.

     During 2006, Pepco Energy Services sold five businesses that served primarily commercial and industrial customers by providing heating, ventilation, air conditioning, electrical testing and maintenance, and building automation services. Net assets sold were approximately $20.7 million.

     Pepco Energy Services also owns and operates two oil-fired power plants. The power plants are located in Washington, D.C. and have a generating capacity rating of approximately 806 MW. Pepco Energy Services sells the output of these plants into the wholesale market administered by PJM. Pepco Energy Services intends to provide notice to PJM of its intention to deactivate these plants. It is expected that the plants would be deactivated no later than May 31, 2012. Deactivation is subject to approval by PJM and will not have a material impact on PHI's financial condition, results of operations or cash flows. See Item 2 "Properties."

     Competition

     The unregulated energy generation, supply and marketing businesses primarily 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 retail energy 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 services offered to customers and quality of service.

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     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 higher in the summer months associated with cooling and demand for electricity and natural gas generally is higher 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 produced less revenue when weather conditions are milder than normal. Milder weather can also negatively impact income from these operations. Energy management services generally are not seasonal.

Other Business Operations

     Over the last several years, PHI has discontinued its investments in non-energy related businesses, including the sale of its aircraft investments and the sale of its 50% interest in Starpower Communications LLC (Starpower). Through its subsidiary, Potomac Capital Investment Corporation (PCI), PHI continues to maintain a portfolio of cross-border energy sale-leaseback transactions, with a book value at December 31, 2006 of approximately $1.3 billion. For additional information concerning these cross-border lease transactions, see Note (12) "Commitments and Contingencies" to the consolidated financial statements of PHI included in Item 8 and Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors." This activity constitutes a separate operating segment for financial reporting purposes, which is designated "Other Non-Regulated."

EMPLOYEES

     At December 31, 2006, PHI had 5,156 employees, including 1,413 employed by Pepco, 907 employed by DPL, 588 employed by ACE and 1,756 employed by PHI Service Company. The balance was employed by PHI's competitive energy and other non-regulated businesses. Approximately 2,760 employees (including 1,084 employed by Pepco, 741 employed by DPL, 431 employed by ACE, 340 employed by PHI Service Company, and the balance employed by PHI's Competitive Energy businesses) are covered by collective bargaining agreements with various locals of the International Brotherhood of Electrical Workers.

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's current capital expenditures plan for the replacement of existing or installation of new environmental control facilities by its subsidiaries is $16.9 million in 2007 and $21.8 million in 2008; however, this plan includes only a portion of the expenditures that may be needed to comply with air quality regulations recently adopted by the Delaware Department of Natural Resources and Environmental Control (DNREC), as described below, if such regulations ultimately are upheld. The actual costs of environmental compliance may be materially different from this capital expenditures plan depending on the outcome of the matters addressed below or

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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 generating 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 generating units and allocates "allowances." The generating 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 generating units and allocate NOx allowances. Most of the generating 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.

     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 regarding 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 pollution control technology and obtain offsets in some circumstances when those sources undergo a "major modification," as defined in the regulations.

     On January 24, 2006, PHI, Conectiv and ACE entered into an administrative consent order (ACO) with NJDEP and the Attorney General of New Jersey resolving New Jersey's claim for alleged violations of the CAA and the NJDEP's concerns regarding ACE's compliance with NSR requirements and the New Jersey Air Pollution Control Act (APCA) with respect to the B.L. England generating facility and various other environmental issues relating to ACE and Conectiv Energy facilities in New Jersey. Among other things, the ACO provides that:

·	Contingent upon the receipt of necessary approvals for the construction of substation and transmission facilities to compensate for the shut down of B.L. England, ACE would permanently cease operation of the B.L. England generating facility by December 15, 2007 if ACE did not sell the facility.
·	If B.L. England were shut down by December 15, 2007, ACE would surrender to NJDEP certain SO2 and NOx allowances allocated to B.L. England Units 1 and 2, contingent upon approval by the NJBPU recognizing cost impacts of the surrender.
·	In the event that ACE were unable to shut down B.L. England Units 1 and 2 by December 15, 2007 through no fault of its own, ACE would surrender NOx and SO2 allowances not needed to satisfy the operational needs of B.L. England Units 1 and 2, contingent upon approval by the NJBPU recognizing cost impacts of the surrender.
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·	To resolve any possible civil liability (and without admitting liability) for violations of APCA and the PSD provisions of the CAA, ACE paid a $750,000 civil penalty to NJDEP in June 2004 and will undertake environmental projects that are beneficial to the state of New Jersey and approved by the NJDEP or donate property valued at $2 million.
·	To resolve any possible civil liability (and without admitting liability) for natural resource damages resulting from groundwater contamination at ACE's B.L. England facility and Conectiv Energy's Deepwater facility and ACE's operations center near Pleasantville, New Jersey, ACE and Conectiv Energy paid NJDEP $674,162 and agreed to remediate the groundwater contamination at all three sites

     As more fully described under "ACE Sale of Generating Assets," on February 8, 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May. In anticipation of the sale, on October 31, 2006, ACE and NJDEP, along with RC Cape May, entered into an amendment to the ACO, pursuant to which RC Cape May, upon closing of the sale, assumed responsibility under the ACO for (i) compliance with the emission limits for B.L. England Units 1 and 2 that take effect December 15, 2012 and May 1, 2010, respectively, and for the payment of any civil penalties for the failure to do so and (ii) the remediation of the groundwater contamination and other resources at the B.L. England facility. In addition, in accordance with the purchase agreement, ACE transferred to RC Cape May NOx and SO₂ allowances sufficient to cover the pre-closing date operational needs of B.L. England to enable RC Cape May to satisfy compliance obligations applicable to pre-closing NOx and S O₂ emissions. On December 6, 2006, the NJBPU approved the sale of the B.L. England generating facility to RC Cape May, along with a stipulation as filed by NJBPU staff, the Ratepayer Advocate, ACE and RC Cape May that the balance of the NOx and SO₂ allowances allocated to B.L. England Units 1 and 2 need not be surrendered to NJDEP and EPA, respectively, but instead should be monetized for the benefit of ACE's ratepayers. The appropriate mechanism for monetizing the value of the NOx and SO₂ allowances for the benefit of ratepayers has been deferred to a Phase II proceeding. Refer to PHI Note (2) "Summary of Significant Accounting Policies" for a discussion of PHI's accounting treatment for emission allowances.

     The ACO does not resolve any federal claims for alleged environmental law violations at the B.L. England generating facility or any federal or state claims regarding alleged environmental law violations at Conectiv Energy's Deepwater generating facility or any other facilities. In accordance with the terms of the purchase and sale agreement with RC Cape May, RC Cape May is responsible for the costs of correcting any alleged environmental law violations at B.L. England and ACE is responsible for any penalties arising out of any alleged environmental law violations. PHI does not believe that any of its subsidiaries has any liability with respect thereto, but cannot predict the consequences of the federal inquiry regarding B.L. England and federal and state inquiries regarding Deepwater.

     EPA finalized its Clean Air Mercury Rule (CAMR) on May 18, 2005. CAMR establishes mercury emissions standards for new or modified sources and caps state-wide emissions of mercury beginning in 2010. States may implement CAMR by adopting EPA's trading program for coal-fired utility boilers or through regulations that at a minimum achieve the reductions that will be achieved through EPA's program. These regulations may require installation of pollution control devices and/or fuel modifications for generating units owned by Conectiv Energy.

     Closely related to CAMR is EPA's Clean Air Interstate Rule (CAIR), released on March 10, 2005, which imposes additional reductions of SO₂ and NOx emissions from electric generating units in 28 Eastern states and the District of Columbia with implementation commencing in

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2009. CAIR caps state-wide emissions of SO₂ and NOx in two stages beginning in 2009 for NOx and 2010 for SO₂. As with CAMR, states may implement CAIR by adopting EPA's trading program or through regulations that at a minimum achieve the reductions through implementation of EPA's program. These regulations may require installation of pollution control devices and/or fuel modifications for generating units owned by Conectiv Energy and Pepco Energy Services.

     In a March 14, 2005 rulemaking, EPA removed coal- and oil-fired units from the list of source categories requiring Maximum Achievable Control Technology for hazardous air pollutants under CAA Section 112, thus, for the time being, eliminating the possibility that control devices would be required under this section of the CAA to reduce nickel emissions from one of the units at Conectiv Energy's Edge Moor generating facility.

     In December 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 federal CAMR 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 of an affected unit to comply with the mercury limits by December 2012 if the owner or operator complies with the mercury limits for 50% of the company's total coal-fired capacity by the December 15, 2007 deadline and enters into an enforceable agreement to comply with the mercury standards, as well as with stringent standards regulating emissions of NOx, SO₂ and particulate matter 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 n ot be applicable to that particular unit. 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 CAMR and at the Edge Moor generating facility to comply with the mercury provisions of Delaware's final multipollutant regulations, discussed below.

     In November 2005, NJDEP finalized regulations that classify carbon dioxide (CO₂) as an air contaminant and enable NJDEP potentially to regulate CO₂ emissions from power plants and other sources. Through its rulemaking and other public announcements, NJDEP has indicated that it will take action to limit or reduce emissions of CO₂ from electric utilities in New Jersey in the near future. New Jersey is one of seven states, including Delaware, Connecticut, Maine, New Hampshire, Vermont and New York, that has agreed to participate in the Regional Greenhouse Gas Initiative (RGGI), which is expected to cap and eventually reduce emissions of CO₂ from power plants within the participating states. In accordance with the terms of the April 2006 Maryland Healthy Air Act, Maryland is required to join RGGI and become a full participant no later than June 30, 2007.

     As RGGI signatories, it is anticipated that both New Jersey and Delaware (and eventually Maryland) will adopt implementing CO₂ regulations in 2007. These regulations are expected to require New Jersey and Delaware fossil fuel-fired electric generating units to hold CO₂ allowances equivalent to its historic baseline CO₂ emissions commencing in 2009 and to incrementally reduce CO₂ emissions beginning in 2015 to achieve an overall 10% reduction from baseline by 2019. Because each state has freedom to adopt its own regulations and can develop its own allowance allocation mechanisms, PHI cannot predict, at this time, if any allowance allocations by these states will fall below the level of CO₂ emissions predicted for the generating facilities operated by PHI's subsidiaries in the affected jurisdictions, or what the potential financial impact of the regulations may be on PHI and its subsidiaries.

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     In addition, on February 13, 2007, the New Jersey Governor signed Executive Order 54, which requires New Jersey to reduce its greenhouse gas emissions to 1990 levels by 2020 and to 80 percent below 2006 levels by 2050. The Executive Order requires NJDEP to coordinate with NJBPU, New Jersey's Department of Transportation and Department of Community Affairs and stakeholders to evaluate policies and measures that will enable New Jersey to achieve the greenhouse gas emissions reduction levels set forth in the Executive Order. PHI cannot predict, at this time, the impact of the Executive Order on PHI and its subsidiaries.

     On November 15, 2006, DNREC adopted regulations to require control strategies to assure attainment of ambient air quality standards for ozone and fine particulate matter, address local scale fine particulate emission problems attributable to coal and residual oil fired electric generating facilities, address mercury emissions from coal fired electric generating facilities, satisfy the federal CAMR rule, improve visibility and help satisfy Delaware's regional haze obligations. For Conectiv Energy's Edge Moor coal fired units, these multipollutant regulations establish stringent short-term emission limits for emissions of NOx, SO₂ and mercury, and for Edge Moor's residual oil fired generating unit, impose more stringent sulfur in fuel limits and establish stringent short-term emission limits for NOx emissions. The regulations also cap annual emissions of NOx and SO₂ from Edge Moor's coal fired and residual oil fired units, and mercury from Edge Moor's co al fired units. Compliance with the regulations will require the installation of new pollution control equipment and/or the enhancement of existing equipment, and may require the imposition of restrictions on the operation of those units. Conectiv Energy is required to submit a compliance plan for its facilities to DNREC on or before July 1, 2007. If the regulations are ultimately upheld, Conectiv Energy estimates that it may cost up to $250 million (of which a total of $50 million is contemplated in PHI's 5-year capital expenditures plan, $31 million of which is included in the capital expenditures plan for 2007 and 2008) to install the control equipment necessary to comply with the regulations. These estimated costs do not include increased costs associated with operating control equipment. The costs associated with installing and operating the equipment necessary to comply with these regulations may impair the economic viability of the Edge Moor units. On December 5, 2006, Conectiv Energy filed an appeal of the final regulation with the Delaware Environmental Appeals Board and on December 8, 2006, filed a complaint seeking review of DNREC's adoption of the regulations in Delaware Superior Court.

     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 generating facilities operated by PHI's subsidiaries have NPDES permits authorizing their pollutant discharges, which are subject to periodic renewal.

     In July 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 as part of the NPDES permit renewal process. However, on January 25, 2007, the United States Court of Appeals for the Second Circuit (the Second Circuit) issued a decision inRiverkeeper, Inc. v. United States Environmental

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Protection Agency and other consolidated dockets (commonly known as theRiverkeeper II decision), that remanded substantial portions of EPA's Section 316(b) regulations. EPA has not yet responded to the Second Circuit's remand of the agency's Section 316(b) regulations or indicated whether it will seek to appeal theRiverkeeper II decision to the U.S. Supreme Court. The capital expenditures required at each facility, if any, likely will not be known until the requirements of the regulations are clarified by EPA on remand, or by the Supreme Court on further appeal ofRiverkeeper II and until each facility completes the studies required by the regulations and related permit requirements.

     The EPA has delegated authority to administer the NPDES program to a number of state agencies including DNREC. The NPDES permit for Conectiv Energy's Edge Moor generating facility expired on October 30, 2003, but has been administratively extended until DNREC issues a renewal permit. Conectiv Energy submitted 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 technologies and operational measures have been evaluated and discussed with DNREC. DNREC, however, has not announced how it intends to address Section 316(b) requirements in NPDES permits in light ofRiverkeeper II and the remand of substantial portions of the Federal regulations. Expenditures to comply with EPA's CWA Section 316(b) performance-based standards are dependent upon DNREC's approval. PHI cannot predict the extent of these expenditures until DNREC and Conectiv Energy agree on a proposed strategy.

     Under the New Jersey Water Pollution Control Act, NJDEP implements regulations, administers the New Jersey Pollutant Discharge Elimination System (NJPDES) program with EPA oversight, and issues and enforces NJPDES permits. The current NJPDES permit for Conectiv Energy's Deepwater generating facility is effective through September 30, 2007, and Conectiv Energy will file an application to renew the permit on or before June 30, 2007. The current NJPDES permit for Deepwater required several studies to determine whether or not Deepwater's cooling water intake structures satisfy applicable requirements for protection of the environment. While those study requirements were consistent with requirements under EPA's regulations implementing CWA Section 316(b), the result of theRiverkeeper II decision and remand may involve reevaluation of the design and operational measures that Conectiv Energy anticipated using for future compliance with Section 316(b) at Deepwater. Althou gh EPA (like NJDEP) is expected to announce plans for responding toRiverkeeper II, the timing of revised regulations and the level of expenditures required to meet future requirements for Section 316(b) compliance are unknown at this point. In addition, in view of the uncertainty associated withRiverkeeper II, Conectiv Energy expects to ask NJDEP to modify a cooling water intake structure design upgrade requirement in Deepwater's current NJPDES permit.

     Pepco and a subsidiary of Pepco Energy Services discharge water from a steam generating plant and service center located in the District of Columbia under a NPDES permit issued by EPA in November 2000. Pepco 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 yet issued the revised draft permit. A timely renewal application was filed in May 2005 and the companies are operating under the November 2000 permit, excluding the withdrawn conditions, in accordance with the settlement agreement.

     In late October 2006, NJDEP proposed amendments to its regulations under the Flood Hazard Area Control Act that would impose a new and highly complex regulatory program on

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electric utility functions that otherwise are comprehensively regulated under a number of other state and federal programs. ACE filed comments on the proposed amendments, urging NJDEP to continue to exempt utility lines, poles, and other utility property from the flood hazard regulations. ACE cannot predict the costs of complying with NJDEP's flood hazard regulations if the amendments are promulgated as proposed.

     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 currently or formerly owned facilities f ound 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 of Financial Condition and Results of Operations -- Capital Resources and Liquidity -- Capital Requirements -- Environmental Remediation Obligations."

Item 1A.   RISK FACTORS

     The businesses of PHI, Pepco, DPL and ACE 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 any one or more of the companies, including, depending on the circumstances, its financial condition, results of operations and cash flows. Unless otherwise noted, each risk factor set forth below applies to each of PHI, Pepco, DPL and ACE.

PHI and its subsidiaries are subject to substantial governmental regulation, and unfavorable regulatory treatment, could have a negative effect.

     PHI's Power Delivery businesses 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 state public service commissions in its service territories, with respect to, among other things, the rates it can charge retail customers for the supply and distribution of electricity (and additionally for DPL the supply and distribution of natural gas). In addition, the rates that the companies can charge for electricity transmission are regulated by FERC, and DPL's natural gas transmission is regulated by the U.S. Department of Transportation. The companies cannot change supply, distribution, or transmission rates without approval by the applicable regulatory authority. While the approved distribution 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 compani es is affected by the rates they are able to charge. In addition, if the costs incurred by any of the companies in operating its 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.

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     PHI's subsidiaries also are required to have numerous permits, approvals and certificates from governmental agencies that regulate their businesses. PHI believes that each of its subsidiaries has, and each of Pepco, DPL and ACE believes 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, none of the companies is able 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 any one or more of PHI's subsidiaries to incur additional expenses or to change the way it conducts its operations.

PHI and Pepco could be adversely affected by the Mirant bankruptcy. (PHI and Pepco only)

     In 2000, Pepco sold substantially all of its electricity generation assets to Mirant Corporation and its subsidiaries (together with its predecessors, Mirant). As part of the sale, Pepco entered into several ongoing contractual arrangements with Mirant. On July 14, 2003, Mirant 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). On May 30, 2006, Pepco, PHI and certain affiliated companies entered into a Settlement Agreement and Release with Mirant (the Settlement Agreement), which, subject to court approval, settles all outstanding issues among the parties arising from or related to the Mirant bankruptcy. On August 9, 2006, the Bankruptcy Court approved the Settlement Agreement, and on August 18, 2006, certain holders of Mirant bankruptcy claims, who had objected to approval of the Settlement Agreement before the Bankruptcy Court appealed the approval order to the U.S. District Court for the Northern District of Texas (the District Court). On December 26, 2006, the District Court issued an order affirming the Bankruptcy Court's order approving the Settlement Agreement. On January 25, 2007, the parties that had appealed the Bankruptcy Court's order filed a notice of appeal of the District Court's order with the United States Court of Appeals for the Fifth Circuit (the Fifth Circuit). On February 12, 2007, the Fifth Circuit issued a briefing schedule. The brief of the appealing creditors is due on March 26, 2007, while Mirant's and Pepco's briefs are due on April 30, 2007. Depending on the outcome of these proceedings, the Mirant bankruptcy could have an adverse effect on PHI and Pepco. See Item 7 "PHI -- Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Relationship with Mirant Corporation" for additional information.

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

     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 Internal Revenue Service (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.

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See Item 7 "PHI -- Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Divestiture Cases" for additional information.

The operating results of the Power Delivery business and the Competitive Energy businesses fluctuate on a seasonal basis and can be adversely affected by changes in weather.

     The Power Delivery business is seasonal and weather patterns can have a material impact on their operating performance. Demand for electricity is generally higher in the summer months associated with cooling and demand for electricity and natural gas is generally higher in the winter months associated with heating as compared to other times of the year. Accordingly, each of PHI, Pepco, DPL and ACE has generated less revenue and income when weather conditions are milder in the winter and cooler in the summer. Historically, the competitive energy operations of Conectiv Energy and Pepco Energy Services also have produced less revenue when weather conditions are milder than normal, which can negatively impact PHI's income from these operations. The Competitive Energy businesses' energy management services generally are not seasonal.

Facilities may not operate as planned or may require significant maintenance expenditures, which could decrease revenues or increase expenses.

     Operation of the Pepco, DPL and ACE transmission and distribution facilities and the Competitive Energy businesses' generation 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 sound engineering practices, may require significant capital expenditures for additions or upgrades to keep them operating at peak efficiency, to comply with changing environmental requirements, or to provide reliable operations. Natural disasters and weather-related incidents, including tornadoes, hurricanes and snow and ice storms, also can disrupt generation, transmission and distribution delivery systems. Operation of generation, transmission and distribution facilities below expected capacity levels can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through i nsurance. Furthermore, if the company owning the facilities is unable to perform its contractual obligations for any of these reasons, that company, and correspondingly PHI, may incur penalties or damages.

The transmission facilities of the Power Delivery business are interconnected with the facilities of other transmission facility owners whose actions could have a negative impact on operations.

     The electricity 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, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, 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 operation s 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

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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 it and on PHI.

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

     The operations of PHI's subsidiaries, including Pepco, DPL and ACE, 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 can require significant capital and other expenditures to, among other things, meet emissions standards, conduct site remediation and perform environmental monitoring. If a company fails to comply with applicable environmental laws and regulations, even if caused by factors beyond its control, such failure could result in the assessment of civil or criminal penalties and liabilities and the need to expend significant sums to come into compliance.

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

     There is growing concern at the federal and state levels about CO₂ and other greenhouse gas emissions. As a result, it is possible that state and federal regulations will be developed that will impose more stringent limitations on emissions than are currently in effect. Any of these factors could result in increased capital expenditures and/or operating costs for one or more generating plants operated by PHI's Conectiv Energy and Pepco Energy Services businesses. Until specific regulations are promulgated, PHI is unable to predict the ultimate effect of any new environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation on PHI's results of operations, financial position, or liquidity.

     PHI, Pepco, DPL and ACE each continues to monitor federal and state activity related to environmental matters in order to analyze their potential operational and cost implications.

     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. Current compliance strategies may not successfully address the relevant standards and interpretations of the future.

Failure to retain and attract key skilled professional and technical employees could have an adverse effect on the operations.

     The ability of each of PHI, Pepco, DPL and ACE to implement its business strategy is dependent on its ability to recruit, retain and motivate employees.  Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect the company's business, operations, and financial condition.

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PHI's Competitive Energy businesses are highly competitive. (PHI only)

     The unregulated energy generation, supply and marketing businesses primarily 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 and retail energy marketers, and traditional utilities. 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, storage, and distribution assets that they do not own or control to deliver wholesale and retail electricity and natural gas and to obtain fuel for their generation facilities. (PHI only)

     PHI's Competitive Energy businesses depend upon electric transmission facilities, natural gas pipelines, and natural gas storage facilities owned and operated by others. The operation of their generation facilities also depends upon coal, natural gas or diesel fuel supplied by others. If electric transmission, natural gas pipelines, or natural gas storage are disrupted or capacity is inadequate or unavailable, the Competitive Energy businesses' ability to buy and receive and/or sell and deliver wholesale and retail power and natural gas, 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 businesses' ability to operate their generating facilities could be adversely affected.

Changes in technology may adversely affect the Power Delivery business and PHI's Competitive Energy businesses.

     Research and development activities are ongoing to improve alternative technologies to produce electricity, including fuel cells, micro turbines 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 the Power Delivery businesses of Pepco, DPL and ACE and PHI's Competitive Energy businesses. Changes in technology also could alter the channels through which retail electric customers buy electricity, which could adversely affect the Power Delivery businesses of Pepco, DPL and ACE.

PHI's risk management procedures may not prevent losses in the operation of its Competitive Energy businesses. (PHI only)

     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 potential one-day favorable or unfavorable price movements. These estimates are based on historical price volatility and assume a normal distribution of price changes and a 95% probability of occurrence. 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

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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. (PHI only)

     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. Each of these various hedge instruments can carry a unique set of risks in their application to PHI's energy assets. PHI must apply judgment in determining the application and effectiveness of each hedge instrument. Changes in accounting rules, or revised interpretations to existing rules, may cause hedges to be deemed ineffective as an accounting matter. This could have material earnings implications for the period or periods in question. Conectiv Energy's objective is to hedge a portion of the expected power output of its gene ration facilities and the costs of fuel used to operate those facilities so it is not completely exposed to spot energy price movements. Hedge targets are approved by PHI's Corporate Risk Management Committee and may change from time to time based on market conditions. Conectiv Energy generally establishes hedge targets annually for the next three succeeding 12-month periods. Within a given 12 month horizon, the actual hedged positioning in any month may be outside of the targeted range, even if the average for a 12 month period falls within the stated range. Management exercises judgment in determining which months present the most significant risk, or opportunity, and hedge levels are adjusted accordingly. Since energy markets can move significantly in a short period of time, hedge levels may also be adjusted to reflect revised assumptions. Such factors may include, but are not limited to, changes in projected plant output, revisions to fuel requirements, transmission constraints, prices of alternate fuels, and improving or deteriorating supply and demand conditions. In addition, short-term occurrences, such as abnormal weather, operational events, or intra-month commodity price volatility may also cause the actual level of hedging coverage to vary from the established hedge targets. These events can cause fluctuations in PHI's earnings from period to period. Due to the high heat rate of the Pepco Energy Services generating facilities, Pepco Energy Services generally does not enter into wholesale contracts to lock in the forward value of its plants. 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. Conversely, by engaging in hedging activities, PHI may not realize gains that otherwise could result from fluctuating commodity prices.

Business operations could be adversely affected by terrorism.

     The threat of, or actual acts of, terrorism may affect the operations of PHI or any of its subsidiaries in unpredictable ways and may cause changes in the insurance markets, force an increase in security measures and cause disruptions of fuel supplies and markets. If any of its infrastructure facilities, 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, the operations of PHI, Pepco, DPL or ACE could be adversely affected. Corresponding instability in the financial markets as a result of terrorism also could adversely affect the ability to raise needed capital.

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Insurance coverage may not be sufficient to cover all casualty losses that the companies might incur.

     PHI. Pepco, DPL and ACE 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.

Revenues, profits and cash flows 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 the Power Delivery businesses of Pepco, DPL and ACE and PHI's 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. (PHI only)

     PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which as of December 31, 2006, had a book value of approximately $1.3 billion and from which PHI currently derives approximately $57 million per year in tax benefits in the form of interest and depreciation deductions. 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.

     As part of the normal PHI tax audit for 2001 and 2002, the IRS disallowed the tax benefits claimed by PHI with respect to these leases for those years. The tax benefits claimed by PHI with respect to these leases from 2001 through December 31, 2006 were approximately $287 million. PHI has filed a protest against the IRS adjustments and the unresolved audit has been forwarded to the IRS Appeals Office. 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 flows. See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Federal Tax Treatment of Cross-Border Leases" for additional information.

Pending tax legislation could result in a loss of future tax benefits from cross-border energy sale and lease-back transactions entered into by a PHI subsidiary. (PHI only)

     On February 1, 2007 the U.S. Senate passed the Small Business and Work Opportunity Act of 2007. Included in this legislation is a provision which would apply passive loss limitation rules to leases with foreign tax indifferent parties effective for taxable years beginning after December 31, 2006. On February 16, 2007 the U.S. House of Representatives passed the Small Business Relief Act of 2007. This bill does not include any provision that would modify the current treatment of leases with tax indifferent parties. Enactment into law of a bill that is similar to that passed by the U.S. Senate in its current form could result in a material delay of the income tax benefits that PCI would receive in connection with its cross-border energy leases. Furthermore, under Financial Accounting Standards Board Staff Position on Financial

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Accounting Standards 13-2, PHI would be required to adjust the book values of its leases and record a charge to earnings equal to the repricing impact of the disallowed deductions which could result in a material adverse effect on PHI's financial condition, results of operations and cash flows. The U.S. House of Representatives and the U.S. Senate are expected to hold a conference in the near future to reconcile the differences in the two bills to determine the final legislation. See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Federal Tax Treatment of Cross-Border Leases" for additional information.

IRS Revenue Ruling 2005-53 on Mixed Service Costs could require PHI to incur additional tax and interest payments in connection with the IRS audit of this issue for the tax years 2001 through 2004 (IRS Revenue Ruling 2005-53).

     During 2001, Pepco, DPL, and ACE changed their methods of accounting with respect to capitalizable construction costs for income tax purposes. The change allowed the companies to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through December 31, 2005, these accelerated deductions generated incremental tax cash flow benefits of approximately $205 million (consisting of $94 million for Pepco, $62 million for DPL, and $49 million for ACE) for the companies, primarily attributable to their 2001 tax returns.

     On August 2, 2005, the Treasury Department released regulations that, if adopted in their current form, would require Pepco, DPL, and ACE to change their method of accounting with respect to capitalizable construction costs for income tax purposes for future tax periods beginning in 2005. Based on those regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believes will be acceptable to the IRS.

     On the same day that the new regulations were released, the IRS issued Revenue Ruling 2005-53, which is intended to limit the ability of certain taxpayers to utilize the method of accounting for income tax purposes they utilized on their tax returns for 2004 and prior years with respect to capitalizable construction costs. In line with this Revenue Ruling, the IRS revenue agent's report for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that Pepco, DPL and ACE had claimed on those returns by requiring the companies to capitalize and depreciate certain expenses rather than treat such expenses as current deductions. PHI has filed a protest against the IRS adjustments and the issue is among the unresolved audit matters relating to the 2001 and 2002 audits pending before the Appeals Office.

     In February 2006, PHI paid approximately $121 million of taxes to cover the amount of taxes that management estimated to be payable based on the method of tax accounting that PHI, pursuant to the proposed regulations, has adopted on its 2005 tax return. However, if the IRS is successful in requiring Pepco, DPL and ACE to capitalize and depreciate construction costs that result in a tax and interest assessment greater than management's estimate of $121 million, PHI will be required to pay additional taxes and interest only to the extent these adjustments exceed the $121 million payment made in February 2006.

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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, Pepco, DPL and ACE each 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 would increase the cost of borrowing or could adversely affect the ability to access one or more financial markets.  In addition, a reduction in PHI's credit ratings could require PHI or its subsidiaries to post additional collateral in connection with some of the Competitive Energy businesses' wholesale marketing and financing activities. 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.

     In accordance with the requirements of the Sarbanes-Oxley Act of 2002 and the SEC rules thereunder, PHI's management is responsible for establishing and maintaining internal control over financial reporting and is required to assess annually the effectiveness of these controls. The inability to certify the effectiveness of these controls due to the identification of one or more material weaknesses in these controls also could increase financing costs or could adversely affect the ability to access one or more financial markets.

Future defined benefit plan funding obligations are affected by assumptions regarding the valuation of its benefit obligations and the performance of plan assets; actual experience which varies from the assumptions could result in an obligation of PHI, Pepco, DPL or ACE to make significant unplanned cash contributions to the Retirement Plan.

     PHI follows the guidance of Statement of Financial Accounting Standards (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, affect the calculation of projected benefit obligations, accumulated benefit obligation (ABO), reported pension liability, regulated assets, or accumulated other comprehensive income on PHI's consolidated balance sheet and on the balance sheets of Pepco, DPL and ACE, and reported annual net periodic pension benefit cost on PHI's consolidated statement of earnings and on the statements of earnings of Pepco, DPL and ACE.

     Use of alternative assumptions could also impact the expected future cash funding requirements of PHI, Pepco, DPL and ACE for the Retirement Plan if the plan did not meet the minimum funding requirements of the Employment Retirement Income Security Act of 1974 (ERISA).

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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 only)

     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, PHI's subsidiaries and the preferred stockholders of ACE 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 ACE's preferred stock to receive dividend paymen ts.

Energy companies are subject to adverse publicity which makes them 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 natural disasters and weather related incidents. Adverse publicity of this nature may render legislatures, regulatory authorities, and other government officials less likely to view energy companies such as PHI and its subsidiaries in a favorable light, and may cause PHI and its subsidiaries to be susceptible to adverse outcomes with respect to decisions by such bodies.

Provisions of the Delaware General Corporation Law may discourage an acquisition of PHI. (PHI only)

     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.

Because Pepco is a wholly owned subsidiary of PHI, and each of DPL and ACE are indirect wholly owned subsidiaries of PHI, PHI can exercise substantial control over their dividend policies and businesses and operations. (Pepco, DPL and ACE only)

     All of the members of Pepco's board of directors are employees of an affiliate of PHI and all of the members of each of DPL's and ACE's board of directors, as well as many of Pepco's, DPL's and ACE's executive officers, are officers of PHI. Among other decisions, each of Pepco's, DPL's and 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, and subject to the financial covenants under each company's respective outstanding debt instruments, each of Pepco's, DPL's and ACE's board of directors will base its decisions concerning the amount and timing of dividends, and other business decisions, on the company's respective 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 1B.   UNRESOLVED STAFF COMMENTS

Pepco Holdings

     None.

Pepco

     Not applicable.

DPL

     Not applicable.

ACE

     Not applicable.

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Item 2.     PROPERTIES

Generation Facilities

     The following table identifies the electric generating facilities owned by PHI's subsidiaries at December 31, 2006.

Electric Generating Facilities		Location	Owner	Generating Capacity
Coal-Fired Units				(kilowatts)
	Edge Moor Units 3 and 4	Wilmington, DE	Conectiv Energy1	260,000
	B L England2	Beesley's Pt., NJ	ACE	284,000
	Deepwater Unit 6	Pennsville, NJ	Conectiv Energy1	80,000
				624,000
Oil Fired Units
	Benning Road	Washington, DC	Pepco Energy Services3	550,000
	Edge Moor Unit 5	Wilmington, DE	Conectiv Energy1	445,000
	B L England2	Beesley's Pt., NJ	ACE	155,000
	Deepwater Unit 1	Pennsville, NJ	Conectiv Energy1	86,000
				1,236,000
Combustion Turbines/Combined Cycle Units
	Hay Road Units 1-4	Wilmington, DE	Conectiv Energy1	545,000
	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 Services3	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
	Edge Moor Unit 10	Wilmington, DE	Conectiv Energy1	13,000
	West	Marshallton, DE	Conectiv Energy1	15,000
	Delaware City	Delaware City, DE	Conectiv Energy1	16,000
	Tasley	Tasley, VA	Conectiv Energy1	26,000
				3,055,000
Landfill Gas-Fired Units
	Fauquier Landfill Project	Fauquier County, VA	Pepco Energy Services4	2,000
	Eastern Landfill Project	Baltimore County, MD	Pepco Energy Services5	3,000
				5,000
Diesel Units
	Crisfield	Crisfield, MD	Conectiv Energy1	10,000
	Bayview	Bayview, VA	Conectiv Energy1	12,000
	B L England2	Beesley's Pt., NJ	ACE	8,000
				30,000
Total Electric Generating Capacity				4,950,000

1	All holdings of Conectiv Energy are owned by its various subsidiaries.
2	On February 8, 2007, ACE completed the sale of the B.L. England generating facility for a price of $9.0 million, subject to adjustment.
3	These facilities are owned by a subsidiary of Pepco Energy Services.
4	This facility is owned by Fauquier Landfill Gas, LLC, of which Pepco Energy Services holds a 75% membership interest.
5	This facility is owned by Eastern Landfill Gas, LLC, of which Pepco Energy Services holds a 75% membership interest.

     The preceding 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

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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, 2006 consisted of approximately 3,600 transmission circuit miles of overhead lines, 160 transmission circuit miles of underground cables, 22,740 distribution circuit miles of overhead lines, and 19,030 distribution circuit miles of underground cables, primarily in their respective service territories. DPL and ACE own and operate distribution system control centers in New Castle, Delaware and Mays Landing, New Jersey, respectively. Pepco also operates a distribution system control center in Maryland. The computer equipment and systems contained in Pepco's 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 natural gas transmission mains, 1,755 pipeline miles of natural gas distribution mains, and 1,281 natural gas pipeline miles of service lines. The natural gas transmission mains include 7.2 miles of pipeline of which DPL owns 10%, which is used for natural gas operations, and of which Conectiv Energy owns 90%, which is used for delivery of natural gas to electric generation facilities.

     Substantially all of the transmission and distribution property, plant and equipment owned by each of Pepco, DPL and ACE is subject to the liens of the respective mortgages under which the companies issue First Mortgage Bonds. See Note (7) "Debt" to the consolidated financial statements of PHI included in Item 8.

Item 3.    LEGAL PROCEEDINGS

Pepco Holdings

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

LITIGATION WITH MIRANT

     In 2000, Pepco sold substantially all of its electricity generation assets to Mirant (formerly Southern Energy, Inc.). In July 2003, Mirant filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the Bankruptcy Court. On December 9, 2005, the Bankruptcy Court approved Mirant's Plan of Reorganization, and the Mirant business emerged from bankruptcy on January 3, 2006, as a new corporation of the same name. On May 30, 2006, Pepco, PHI and certain affiliated companies entered into the Settlement Agreement, which, subject to court approval, settles all outstanding issues among the parties arising from or related to the Mirant bankruptcy. On August 9, 2006, the Bankruptcy Court approved the Settlement Agreement, and on August 18, 2006, certain holders of Mirant bankruptcy claims, who had

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objected to approval of the Settlement Agreement before the Bankruptcy Court appealed the approval order to the District Court. On December 26, 2006, the District Court issued an order affirming the Bankruptcy Court's order approving the Settlement Agreement. On January 25, 2007, the parties that previously appealed the Bankruptcy Court's order filed a notice of appeal of the District Court's order with the Fifth Circuit. On February 12, 2007, the Fifth Circuit issued a briefing schedule. The brief of the appealing creditors is due on March 26, 2007, while Mirant's and Pepco's briefs are due on April 30, 2007.

     For further information concerning the litigation with Mirant and other litigation matters in addition to those described below, please refer to Note (12), "Commitments and Contingencies," to the Financial Statements of PHI included in Item 8 "Financial Statements and Supplementary Data" herein and to the section headed "Regulatory and Other Matters -- Relationship with Mirant Corporation" included in Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.

GENERAL LITIGATION

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

     Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed. As a result of two motions to dismiss, numerous hearings and meetings and one motion for summary judgment, Pepco has had approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of January 31, 2007, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland; of which 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 between Pepco and Mirant relating to the sale of Pepco's generation assets. Under the terms of the Settlement Agreement, Mirant has agreed to assume this contractual obligation. For a description of the Settlement Agreement, see the discussion of the relationship with Mir ant in Note (12), "Commitments and Contingencies," to the Financial Statements of PHI included in Item 8 "Financial Statements and Supplementary Data" herein and to the section headed "Regulatory and Other Matters -- Relationship with Mirant Corporation" included in Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.

     While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) exceeds $360 million, PHI and Pepco believe 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, neither PHI nor Pepco believes these suits will have a material adverse effect on its financial position, results of operations or cash flows. However, if an

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

CASH BALANCE PLAN LITIGATION

     In 1999, Conectiv established a cash balance retirement plan to replace defined benefit retirement plans then maintained by ACE and DPL. Following the acquisition by Pepco of Conectiv, this plan became the Conectiv Cash Balance Sub-Plan within the PHI Retirement Plan. On September 26, 2005, three management employees of PHI Service Company filed suit in the United States District Court for the District of Delaware (the Delaware District Court) against the PHI Retirement Plan, PHI and Conectiv (the PHI Parties), alleging violations of ERISA, on behalf of a class of management employees who did not have enough age and service when the Cash Balance Sub-Plan was implemented in 1999 to assure that their accrued benefits would be calculated pursuant to the terms of the predecessor plans sponsored by ACE and DPL. A fourth plaintiff was added to the case to represent DPL-heritage "grandfathered" employees who will not be eligible for early retirement at the end of the grandfathere d period.

     The plaintiffs have challenged the design of the Cash Balance Sub-Plan and are seeking a declaratory judgment that the Cash Balance Sub-Plan is invalid and that the accrued benefits of each member of the class should be calculated pursuant to the terms of the predecessor plans. Specifically, the complaint alleges that the use of a variable rate to compute the plaintiffs' accrued benefit under the Cash Balance Sub-Plan results in reductions in the accrued benefits that violate ERISA. The complaint also alleges that the benefit accrual rates and the minimal accrual requirements of the Cash Balance Sub-Plan violate ERISA as did the notice that was given to plan participants upon implementation of the Cash Balance Sub-Plan.

     The PHI Parties filed a motion to dismiss the suit, which was denied by the court on July 11, 2006. The Delaware District Court stayed one count of the complaint regarding alleged age discrimination pending a decision in another case before the United States Court of Appeals for the Third Circuit (the Third Circuit). On January 30, 2007, the Third Circuit issued a ruling in the other case that PHI's counsel believes should result in the favorable disposition of all of the claims (other than the claim of inadequate notice) against the PHI Parties in the Delaware District Court. The PHI Parties filed pleadings apprising the Delaware District Court of the Third Circuit's decision on February 16, 2007, at the same time they filed their opposition to plaintiffs' motion.

     While PHI believes it has an increasingly strong legal position in the case and that it is therefore unlikely that the plaintiffs will prevail, PHI estimates that, if the plaintiffs were to prevail, the ABO and projected benefit obligation (PBO), calculated in accordance with SFAS No. 87, each would increase by approximately $12 million, assuming no change in benefits for persons who have already retired or whose employment has been terminated and using actuarial valuation data as of the time the suit was filed. The ABO represents the present value that participants have earned as of the date of calculation. This means that only service already worked and compensation already earned and paid is considered. The PBO is similar to the ABO, except that the PBO includes recognition of the effect that estimated future pay increases would have on the pension plan obligation.

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ENVIRONMENTAL LITIGATION

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

     In July 2004, DPL entered into an ACO 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 a Cambridge, Maryland site on DPL-owned property and to investigate the extent of MGP contamination on adjacent property. The MDE has approved the RI and DPL submitted a final FS to MDE on February 15, 2007. The costs of cleanup (as determined by the RI/FS and subsequent negotiations with MDE) are anticipated to be approximately $2.7 million. The remedial action will include dredging activities within Cambridge Creek, which are expected to take place as early as October 2007, and soil excavation on DPL's and adjacent property as early as January 2008.

     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 the 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 1994, an RI/FS including a number of possible remedies was submitted to the EPA. In 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 1998, the EPA issued a unilateral administrative order to Pepco and 12 other PRPs directing them to conduct the design and actions called for in its decision. In May 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. In October 2003, the bankruptcy court confirmed a reorganization plan that incorporates the terms of a settlement among the two debtor owner/operator entities, the United States and a group of utility PRPs including Pepco (the Utility PRPs). Under the bankruptcy settlement, the reorganized entity/site owner will pay a total of $13.25 million to remediate the site (the Bankruptcy Settlement).

     In March 2006, the United States District Court for the Eastern District of Pennsylvania approved global consent decrees for the Metal Bank/Cottman Avenue site, entered into on August 23, 2005, involving the Utility PRPs, the U.S. Department of Justice, EPA, The City of Philadelphia and two owner/operators of the site. Under the terms of the settlement, the two owner/operators will make payments totaling $5.55 million to the U.S. Department of Justice and totaling $4.05 million to the Utility PRPs. The Utility PRPs will perform the remedy at the site and will be able to draw on the $13.25 million from the Bankruptcy Settlement to accomplish the remediation (the Bankruptcy Funds). The Utility PRPs will contribute funds to the extent remediation costs exceed the Bankruptcy Funds available. The Utility PRPs also will be liable

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for EPA costs associated with overseeing the monitoring and operation of the site remedy after the remedy construction is certified to be complete and also the cost of performing the "5 year" review of site conditions required by CERCLA. Any Bankruptcy Funds not spent on the remedy may be used to cover the Utility PRPs' liabilities for future costs. No parties are released from potential liability for damages to natural resources.

     As of December 31, 2006, Pepco had accrued $1.7 million to meet its liability for a remedy at the Metal Bank/Cottman Avenue site. While final costs to Pepco of the settlement have not been determined, Pepco believes that its liability at this site will not have a material adverse effect on its financial position, results of operations or cash flows.

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

     In November 1991, the 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 ACO 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. Positive results of groundwater monitoring events have resulted in a reduced level of groundwater monitoring. In August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site. Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years and to continue groundwater monitoring.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 anticipates that its share of additional cost associated with this site will be approximately $555,000 to $600,000. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial position, results of operations or cash flows.

     On January 24, 2006, PHI, Conectiv and ACE entered into an ACO with NJDEP and the Attorney General of New Jersey resolving (i) New Jersey's claim for alleged violations of the CAA and (ii) the NJDEP's concerns regarding ACE's compliance with NSR requirements of the CAA and APCA requirements with respect to the B.L. England generating facility and various other environmental issues relating to ACE and Conectiv Energy facilities in New Jersey. See Item 1 "Business -- Environmental Matters -- Air Quality Regulation."

OTHER LEGAL PROCEEDINGS

     For further information concerning other legal proceedings, please refer to Note (12), "Commitments and Contingencies," to the financial statements of PHI included herein.

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

Pepco Holdings

     None.

     INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, 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.

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
2006:
First Quarter	$  .26	$24.28	$22.15
Second Quarter	.26	23.92	21.79
Third Quarter	.26	25.50	22.64
Fourth Quarter	.26	26.99	24.25
	$1.04
2005:
First Quarter	$  .25	$23.25	$20.26
Second Quarter	.25	24.20	20.50
Third Quarter	.25	24.46	21.87
Fourth Quarter	.25	23.89	20.36
	$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, 2006, there were approximately 68,186 holders of record of Pepco Holdings common stock.

PHI Subsidiaries

     All of the common equity of Pepco, DPL, and ACE is owned directly or indirectly by PHI. 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
2006:
First Quarter	$ 15,000,000
Second Quarter	49,000,000
Third Quarter	-
Fourth Quarter	35,000,000
	$ 99,000,000
2005:
First Quarter	$ 14,933,000
Second Quarter	-
Third Quarter	48,000,000
Fourth Quarter	-
	$ 62,933,000

     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
2006:
First Quarter	$ 15,000,000
Second Quarter	-
Third Quarter	-
Fourth Quarter	-
	$ 15,000,000
2005:
First Quarter	$ 24,384,000
Second Quarter	12,052,000
Third Quarter	-
Fourth Quarter	-
	$ 36,436,000

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     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
2006:
First Quarter	$   19,000,000
Second Quarter	-
Third Quarter	75,000,000
Fourth Quarter	15,000,000
	$109,000,000
2005:
First Quarter	$    7,348,000
Second Quarter	40,539,000
Third Quarter	-
Fourth Quarter	48,000,000
	$  95,887,000

Purchases of Equity Securities by the Issuer and Affiliated Purchasers.

Pepco Holdings

     None.

Pepco

     None.

DPL

     None.

ACE

     None.

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Item 6.    SELECTED FINANCIAL DATA
PEPCO HOLDINGS CONSOLIDATED FINANCIAL HIGHLIGHTS
		2006		2005		2004		2003		2002
		(Millions of dollars, except share data)
Consolidated Operating Results
Total Operating Revenue	$	8,362.9		8,065.5		7,223.1		7,268.7		4,324.5
Total Operating Expenses	$	7,669.6	(a)	7,160.1	(c) (d) (e)	6,451.0		6,658.0	(h) (i)	3,778.6
Operating Income	$	693.3		905.4		772.1		610.7		545.9
Other Expenses	$	282.4	(b)	285.5		341.4		433.3	(j)	191.4
Preferred Stock Dividend   Requirements of Subsidiaries	$	1.2		2.5		2.8		13.9		20.6
Income Before Income Tax Expense   and Extraordinary Item	$	409.7		617.4		427.9		163.5		333.9
Income Tax Expense	$	161.4		255.2	(f)	167.3	(g)	62.1		124.9
Income Before Extraordinary Item	$	248.3		362.2		260.6		101.4		209.0
Extraordinary Item	$	-		9.0		-		5.9		-
Net Income	$	248.3		371.2		260.6		107.3		209.0
Redemption Premium on   Preferred Stock	$	(.8)		(.1)		.5		-		-
Earnings Available for   Common Stock	$	247.5		371.1		261.1		107.3		209.0
Common Stock Information
Basic Earnings Per Share of Common   Stock Before Extraordinary Item	$	1.30		1.91		1.48		.60		1.59
Basic - Extraordinary Item Per   Share of Common Stock	$	-		.05		-		.03		-
Basic Earnings Per Share   of Common Stock	$	1.30		1.96		1.48		.63		1.59
Diluted Earnings Per Share   of Common Stock Before   Extraordinary Item	$	1.30		1.91		1.48		.60		1.59
Diluted - Extraordinary Item Per   Share of Common Stock	$	-		.05		-		.03		-
Diluted Earnings Per Share   of Common Stock	$	1.30		1.96		1.48		.63		1.59
Weighted Average Shares Outstanding		190.7		189.0		176.8		170.7		131.1
Cash Dividends Per Share   of Common Stock	$	1.04		1.00		1.00		1.00		1.00
Year-End Stock Price	$	26.01		22.37		21.32		19.54		19.39
Net Book Value per Common Share	$	18.82		18.88		17.74		17.31		17.49
Other Information
Investment in Property, Plant   and Equipment	$	11,819.7		11,441.0		11,109.4		10,815.2		10,699.7
Net Investment in Property, Plant   and Equipment	$	7,576.6		7,368.8		7,152.2		7,032.9		7,118.0
Total Assets	$	14,243.5		14,038.9		13,374.6		13,390.2		13,479.4
Capitalization
Short-term Debt	$	349.6		156.4		319.7		518.4		971.1
Long-term Debt	$	3,768.6		4,202.9		4,362.1		4,588.9		4,287.5
Current Maturities of Long-Term Debt	$	857.5		469.5		516.3		384.9		408.1
Transition Bonds issued by ACE Funding	$	464.4		494.3		523.3		551.3		425.3
Capital Lease Obligations due within   one year	$	5.5		5.3		4.9		4.4		4.1
Capital Lease Obligations	$	111.1		116.6		122.1		126.8		131.3
Long-Term Project Funding	$	23.3		25.5		65.3		68.6		28.6
Debentures issued to Financing Trust	$	-		-		-		98.0		-
Trust Preferred Securities	$	-		-		-		-		290.0
Minority Interest	$	24.4		45.9		54.9		108.2		110.7
Common Shareholders' Equity	$	3,612.2		3,584.1		3,339.0		2,974.1		2,972.8
Total Capitalization	$	9,216.6		9,100.5		9,307.6		9,423.6		9,629.5

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Notes:	As a result of the acquisition of Conectiv by Pepco that was completed on August 1, 2002, PHI's 2006, 2005, 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 the full year in 2002.
(a)	Includes $18.9 million of impairment losses ($13.7 million after-tax) related to certain energy services business assets.
(b)	Includes $12.3 million gain ($7.9 million after-tax) on the sale of its equity interest in a joint venture which owns a wood burning cogeneration facility in California.
(c)	Includes $68.1 million ($40.7 million after-tax) gain from sale of non-utility land owned by Pepco at Buzzard Point.
(d)	Includes $70.5 million ($42.2 million after-tax) gain (net of customer sharing) from settlement of Pepco's $105 million allowed, pre-petition general unsecured claim against Mirant and the Pepco asbestos claim against the Mirant bankruptcy estate.
(e)	Includes $13.3 million ($8.9 million after-tax) related to PCI's liquidation of a financial investment that was written off in 2001.
(f)	Includes $10.9 million in income tax expense related to the mixed service cost issue under IRS Revenue Ruling 2005-53.
(g)	Includes a $19.7 million charge related to an IRS settlement. Also includes $13.2 million tax benefit related to issuance of a local jurisdiction's final consolidated tax return regulations.
(h)	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.
(i)	Includes the unfavorable impact of $44.3 million ($26.6 million after-tax) resulting from trading losses prior to the cessation of proprietary trading.
(j)	Includes an impairment charge of $102.6 million ($66.7 million after-tax) related to investment in Starpower.
40 ___________________________________________________________________________________

     INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, 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 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	43
Pepco	110
DPL	117
ACE	125
41 ___________________________________________________________________________________

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

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

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

     In 2006, 2005, and 2004, respectively, PHI's Power Delivery operations produced 61%, 58% and 61% of PHI's consolidated operating revenues (including revenues from intercompany amounts) and 67%, 74% and 70% of PHI's consolidated operating income (including income from intercompany transactions).

     The Power Delivery business consists primarily of the transmission, distribution and default supply of electric power, which for 2006, 2005, and 2004, was responsible for 95%, 94% and 95%, respectively, of Power Delivery's operating revenues. The distribution of natural gas contributed 5%, 6% and 5% of Power Delivery's operating revenues in 2006, 2005 and 2004, respectively. Power Delivery represents one operating segment for financial reporting purposes.

     The Power Delivery business is conducted by three utility subsidiaries: Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE). Each of these companies is a regulated public utility in the jurisdictions that comprise its service territory. Each company is responsible for the distribution of electricity and, in the case of DPL, natural gas in its service territory, for which it is paid tariff rates established by the applicable local public service commissions. Each company also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service varies by jurisdiction as follows:

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

     In this Form 10-K, these supply service obligations are referred to generally as Default Electricity Supply.

     Pepco, DPL and ACE are also responsible for the transmission of wholesale electricity into and across their service territories. The rates each company is permitted to charge for the wholesale transmission of electricity are regulated by the Federal Energy Regulatory

43

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Commission (FERC). Effective June 1, 2006, new FERC-approved transmission rates took effect for each of PHI's utility subsidiaries. These new rates incorporate true-ups for the formula rates that went into effect June 1, 2005, on a tentative basis, which reflected a requested 12.9% return on equity, as compared to the approved rates, which were based on a return on equity of 10.8% for existing facilities and 11.3% for facilities put into service on or after January 1, 2006. For the year ended December 31, 2006, lower transmission revenues resulted in a $.06 decrease in PHI's earnings per share as compared to the year ended December 31, 2005, a portion of which was attributable to the lower rates combined with the operation of the true-up adjustment to compensate for the higher tentative rates. PHI expects the lower rates in effect and the true-up to have a similar proportionate impact on earnings through May 2007 as compared to 2005 earnings. However, because the magnitude of the true-u p for this first twelve-month period, June 2006 through May 2007, was attributable in part to the transition to the new formula rate process, PHI expects that the impact of the annual true-up adjustment will be less significant in future years.

     The profitability of the Power Delivery business depends on its ability to recover costs and earn a reasonable return on its capital investments through the rates it is permitted to charge. Power Delivery's operating revenue and income are seasonal, and weather patterns may have a material impact on operating results. In addition, customer usage may be affected by economic conditions, energy prices, and energy efficiency measures.

     The Competitive Energy business provides competitive generation, marketing and supply of electricity and gas, and related energy management services primarily in the mid-Atlantic region. These operations are conducted through subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv Energy) and Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), each of which is treated as a separate operating segment for financial reporting purposes. For the years ended December 31, 2006, 2005 and 2004, theoperating revenues of the Competitive Energy business (including revenue from intercompany transactions) were equal to 46%, 51% and 50%, respectively, of PHI's consolidated operating revenues, and the operating income of the Competitive Energy business (including operating income from intercompany transactions) was 20%, 16% and 19% of PHI's consolidated operating income for the years ended December 31, 2006, 2005 and 2004 , respectively. For the years ended December 31, 2006, 2005 and 2004, amounts equal to 12%, 14% and 16% respectively, of the operating revenues of the Competitive Energy business were attributable to electric energy and capacity, and natural gas sold to the Power Delivery segment.

·	Conectiv Energy provides wholesale electric power, capacity and ancillary services in the wholesale markets administered by PJM Interconnection, LLC (PJM) and also supplies electricity to other wholesale market participants under long- and short-term bilateral contracts. Conectiv Energy also supplies electric power to satisfy a portion of ACE's New Jersey, Pepco's Maryland and DPL's Delaware, Maryland, and Virginia Default Electricity Supply load, as well as default electricity supply load shares of other utilities. PHI refers to these activities as Merchant Generation & Load Service. Conectiv Energy obtains the electricity required to meet its Merchant Generation & Load Service power supply obligations from its own generation plants, bilateral contract purchases from other wholesale market participants, and 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. P HI refers to these sales operations as Energy Marketing.
44 ___________________________________________________________________________________
·	Pepco Energy Services provides retail energy supply and energy services primarily to commercial, industrial, and government customers. Pepco Energy Services sells electricity and natural gas to customers primarily in the mid-Atlantic region. Pepco Energy Services owns and operates two district energy systems, provides energy savings performance contracting services, and designs, constructs and operates combined heat and power and central energy plants. Pepco Energy Services provides high voltage construction and maintenance services to customers throughout the U.S. and low voltage construction and maintenance services in the Washington, D.C. area and owns and operates electric generating plants in Washington, D.C.

     Conectiv Energy's primary objective is to maximize the value of its generation fleet by leveraging its operational and fuel flexibilities. Pepco Energy Services' primary objective is to capture retail energy supply and service opportunities primarily 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.

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

     Over the last several years, PHI has discontinued its investments in non-energy related businesses, and has sold its aircraft investments and its 50% interest in Starpower Communications, LLC (Starpower). Through its subsidiary, Potomac Capital Investment Corporation (PCI), PHI continues to maintain a portfolio of cross-border energy sale-leaseback transactions with a book value at December 31, 2006 of approximately $1.3 billion. This activity constitutes a fourth operating segment, which is designated as "Other Non-Regulated," for financial reporting purposes. For a discussion of PHI's cross-border leasing transactions, see "Regulatory and Other Matters -- Federal Income Tax Treatment of Cross-Border Leases" below.

BUSINESS STRATEGY

     PHI's business strategy is to remain a regional diversified energy delivery utility and competitive energy services company focused on value creation and operational excellence. This strategy has three primary components:

· Achieving earnings growth in the Power Delivery business by focusing on infrastructure investments and constructive regulatory outcomes, while maintaining a high level of operational excellence.

· Supplementing PHI's utility earnings through competitive energy businesses that focus on serving the competitive wholesale and retail markets primarily in PJM.

· Maintaining PHI's investment grade credit ratings.

EARNINGS OVERVIEW

Year Ended December 31, 2006 Compared to the Year Ended December 31, 2005

     PHI's net income for the year ended December 31, 2006 was $248.3 million, or $1.30 per share, compared to $371.2 million, or $1.96 per share, for the year ended December 31, 2005.

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     Net income for the year ended December 31, 2006, included the credits (charges) set forth below, which are presented net of federal and state income taxes and are in millions of dollars. The operating segment that recognized the credits (charges) is also indicated.

·	Conectiv Energy
		Gain on the disposition of assets associated with a    cogeneration facility	$    7.9
·	Pepco Energy Services
		Impairment losses related to certain energy   services business assets	$(13.7)

     Net income for year ended December 31, 2005, included the credits (charges) set forth below, which are presented net of federal and state income taxes and are in millions of dollars. The operating segment that recognized the credits (charges) is also indicated.

·	Power Delivery
	-	Favorable impact of $5.1 related to the ACE base rate case settlement as follows:
			Ordinary loss from write-offs of regulatory assets,    net of reserve	$  (3.9)
			Extraordinary gain from reversal of restructuring reserves	9.0
			Total	$   5.1
	-	Gain on sale of assets, specifically non-utility land		$ 40.7
	-	Increase in income tax expense for the interest accrued on    the potential impact of Internal Revenue Service (IRS)    mixed service cost issue		$(10.9)
	-	Gain on settlement of Pepco's $105 million allowed,    pre-petition general unsecured claim against Mirant    Corporation and its predecessors and its subsidiaries    (Mirant) (the Pepco TPA Claim) and the Pepco asbestos    claim against Mirant bankruptcy estate		$ 42.2
·	Conectiv Energy
	-	Impairment charge to reduce the value of an investment in a    jointly owned generation project		$ (2.6)
·	Other Non-Regulated
	-	Gain related to the final liquidation of a PCI financial    investment that was written off in a prior year		$  8.9

     Excluding the items listed above for the year ended December 31, net income would have been $254.1 million in 2006 and $287.8 million in 2005.

     PHI's net income for the years ended December 31, 2006 and 2005, by operating segment, is set forth in the table below (millions of dollars):

46

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	2006	2005	Change
Power Delivery	$191.3	$302.1	$(110.8)
Conectiv Energy	47.1	48.1	(1.0)
Pepco Energy Services	20.6	25.7	(5.1)
Other Non-Regulated	50.2	43.7	6.5
Corp. & Other	(60.9)	(48.4)	(12.5)
Total PHI Net Income	$248.3	$371.2	$(122.9)

Discussion of Operating Segment Net Income Variances:

     Power Delivery's earnings were $110.8 million lower in 2006 compared to 2005 primarily due to the following:

· $42.2 million decrease in earnings due to the gain on settlement of Pepco TPA Claim and Pepco asbestos claim against Mirant bankruptcy estate in 2005.

· $40.7 million decrease in earnings due to the gain on sale of assets (specifically, non-utility land) in 2005.

· $33.9 million decrease in earnings due to lower regulated distribution sales, primarily the impact of milder weather.

· $10.9 million decrease in earnings due to a FERC network transmission formula rate change in June 2006.

· $5.1 million decrease in earnings as a result of the reversal of restructuring reserves associated with the ACE base rate case settlement in 2005.

· $3.6 million decrease in earnings related to a change in the 2005 unbilled revenue accrual balance of ACE.

· $3.1 million decrease in operation and maintenance expenses (primarily lower employee expenses and outside legal services; partially offset by increased electric system emergency restoration and maintenance activity).

· $2.8 million increase in Default Electricity Supply margins, primarily as a result of higher procurement costs for the period January 22, 2005 to February 8, 2005 (which represents the period between the expiration of certain transition power agreements between Pepco and Mirant and commencement of the fully compensatory SOS rates in the District of Columbia).

· $7.4 million increase in earnings resulting from a charge in 2005 related to a change by DPL and ACE in the estimation of unbilled revenue, primarily reflecting an increase in the amount of estimated power line losses.

· $20.6 million increased earnings related to a reduction in income taxes (primarily due to a 2005 accrual of $10.9 million for the potential impact of the mixed service cost issue and other favorable tax audit adjustments in 2006).

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     Power Delivery realized a .9% growth in the number of customers in 2006. However, weather adjusted sales for the calendar year 2006 have decreased by .7% in 2006 compared to an increase of 1.2% in 2005.

     Conectiv Energy's earnings were $1.0 million lower in 2006 compared to 2005 primarily due to the following:

· $21.8 million decrease resulting primarily from milder weather, lower spark spreads, and an unplanned outage at Hay Road resulted in 26% decrease in generation output, which was partially offset by favorable hedges.

· $3.1 million increase in operation and maintenance expenses.

· $8.8 million decrease in earnings from other net activity (higher interest expense, 2005 Burney distribution and termination of an agreement to provide operating services with an unaffiliated operating plant).

· $12.3 million increase resulting primarily from increased margins from new default electricity supply contracts, lower supply costs, and a mark-to-market gain on a supply contract.

· $9.9 million increase related to higher Energy Marketing margins.

· $7.9 million gain on the disposition of assets associated with a cogeneration facility.

· $2.6 million increase in earnings due to an impairment charge to reduce the value of an investment in an energy project in 2005.

     Pepco Energy Services' earnings were $5.1 million lower in 2006 compared to 2005 primarily due to the following:

· $13.7 million (net of tax) of impairment losses related to certain energy services business assets.

· $7.6 million decrease in earnings from the power generation plants (milder weather and higher fuel oil prices in 2006 resulted in 62% lower generation output).

· $12.4 million increase in earnings from its retail energy supply business, primarily due to more favorable supply costs and gains on sale of excess energy supply in 2006.

· $5.3 million increase in earnings from energy services activity due to increased construction projects and thermal energy sales in 2006.

     Other Non-Regulated earnings were $6.5 million higher in 2006 compared to 2005 primarily due to the following:

· $6.2 million increase in earnings due to favorable tax audit adjustments.

· $2.5 million increase in financial investment earnings (including the gain in 2005 related to the final liquidation of a financial investment that was written off in a prior year).

· $2.0 million increase in earnings due to decreases in interest and other expenses.

· $4.8 million decrease in earnings due to gain on the sale of PCI's Solar Electric Generation Stations investment in 2005.

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     Corp. & Other earnings were $12.5 million lower in 2006 compared to 2005 primarily due to the $9.1 million recorded by the affected operating segments and eliminated in consolidation through Corp. & Other.

CONSOLIDATED RESULTS OF OPERATIONS

     The following results of operations discussion is for the year ended December 31, 2006, compared to the year ended December 31, 2005. All amounts in the tables (except sales and customers) are in millions.

Operating Revenue

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

	2006		2005		Change
Power Delivery	$	5,118.8	$	4,702.9	$	415.9
Conectiv Energy		2,157.3		2,603.6		(446.3)
Pepco Energy Services		1,668.9		1,487.5		181.4
Other Non-Regulated		90.6		84.5		6.1
Corp. & Other		(672.7)		(813.0)		140.3
Total Operating Revenue	$	8,362.9	$	8,065.5	$	297.4

     Power Delivery Business

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

	2006		2005		Change
Regulated T&D Electric Revenue	$	1,533.2	$	1,623.2	$	(90.0)
Default Supply Revenue		3,271.9		2,753.0		518.9
Other Electric Revenue		58.3		65.2		(6.9)
Total Electric Operating Revenue		4,863.4		4,441.4		422.0
Regulated Gas Revenue		204.8		198.7		6.1
Other Gas Revenue		50.6		62.8		(12.2)
Total Gas Operating Revenue		255.4		261.5		(6.1)
Total Power Delivery Operating Revenue	$	5,118.8	$	4,702.9	$	415.9

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

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

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

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

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

     Electric Operating Revenue

Regulated T&D Electric Revenue
	2006		2005		Change
Residential	$	575.7	$	613.0	$	(37.3)
Commercial		699.0		726.8		(27.8)
Industrial		28.6		36.8		(8.2)
Other (Includes PJM)		229.9		246.6		(16.7)
Total Regulated T&D Electric Revenue	$	1,533.2	$	1,623.2	$	(90.0)

Regulated T&D Electric Sales (gigawatt hours (Gwh))
	2006		2005		Change
Residential		17,139		18,045		(906)
Commercial		28,638		29,441		(803)
Industrial		4,119		4,288		(169)
Total Regulated T&D Electric Sales		49,896		51,774		(1,878)

Regulated T&D Electric Customers (000s)
	2006		2005		Change
Residential		1,605		1,591		14
Commercial		198		196		2
Industrial		2		2		-
Total Regulated T&D Electric Customers		1,805		1,789		16

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

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

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

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     Regulated T&D Revenue decreased by $90.0 million primarily due to the following: (i) $51.2 million decrease in sales due to weather, the result of a 16% decrease in Heating Degree Days and 12% decrease in Cooling Degree Days in 2006, (ii) $18.5 million decrease due to a change in Delaware rate structure effective May 1, 2006, which shifted revenue from Regulated T&D Electric Revenue to Default Supply Revenue, (iii) $17.1 million decrease in network transmission revenues due to lower rates approved by FERC in June 2006, (iv) $7.0 million decrease due to a Delaware base rate reduction effective May 1, 2006, primarily offset by (v) $12.9 million increase in sales due to a 0.9% increase in the number of customers.

     Default Electricity Supply

Default Supply Revenue
	2006		2005		Change
Residential	$	1,482.2	$	1,161.7	$	320.5
Commercial		1,348.6		994.9		353.7
Industrial		108.2		134.2		(26.0)
Other (Includes PJM)		332.9		462.2		(129.3)
Total Default Supply Revenue	$	3,271.9	$	2,753.0	$	518.9

Default Electricity Supply Sales (Gwh)
	2006		2005		Change
Residential		16,698		17,490		(792)
Commercial		14,799		15,020		(221)
Industrial		1,379		2,058		(679)
Other		129		157		(28)
Total Default Electricity Supply Sales		33,005		34,725		(1,720)

Default Electricity Supply Customers (000s)
	2006		2005		Change
Residential		1,575		1,557		18��
Commercial		170		181		(11)
Industrial		1		2		(1)
Other		2		2		-
Total Default Electricity Supply Customers		1,748		1,742		6

     Default Supply Revenue increased $518.9 million, representing an 18.8% increase despite a 5% decrease in Gwh sales. This increase was primarily due to the following: (i) an increase of $709.3 million attributable to higher retail electricity rates, primarily resulting from market based rates beginning in Delaware on May 1, 2006 and annual increases in Default Electricity Supply rates during the year in the District of Columbia, Maryland, New Jersey, and Virginia, primarily offset by (ii) $142.1 million decrease in wholesale energy revenues from sales of generated and purchased energy in PJM due to lower market prices in the third quarter of 2006 and the sale by ACE of its interests in the Keystone and Conemaugh generating plants, effective September 1, 2006, and (iii) $93.1 million decrease in sales due to milder weather (a 16% decrease in Heating Degree Days and a 12% decrease in Cooling Degree Days in 2006).

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     Other Electric Revenue

     Other Electric Revenue decreased $6.9 million to $58.3 million in 2006 from $65.2 million in 2005 primarily due to a decrease in customer requested work.

     Gas Operating Revenue

Regulated Gas Revenue
	2006		2005		Change
Residential	$	116.2	$	115.0	$	1.2
Commercial		73.0		68.5		4.5
Industrial		10.3		10.6		(.3)
Transportation and Other		5.3		4.6		.7
Total Regulated Gas Revenue	$	204.8	$	198.7	$	6.1

Regulated Gas Sales (billion cubic feet (Bcf)
	2006		2005		Change
Residential		6.6		8.4		(1.8)
Commercial		4.6		5.6		(1.0)
Industrial		.8		1.1		(.3)
Transportation and Other		6.3		5.6		.7
Total Regulated Gas Sales		18.3		20.7		(2.4)

Regulated Gas Customers (000s)
	2006		2005		Change
Residential		112		111		1
Commercial		9		9		-
Industrial		-		-		-
Transportation and Other		-		-		-
Total Regulated Gas Customers		121		120		1

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

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

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

Regulated Gas Revenue increased by $6.1 million primarily due to (i) a $33.2 million increase in revenues as the result of Gas Cost Rate (GCR) increases effective November 1, 2006 and November 1, 2005, as a result of higher natural gas commodity costs (primarily offset in Fuel and Purchased Energy and Other Services Costs of Sales expense), offset by (ii) a $22.3 million decrease in sales due to milder weather (a 17% decrease in Heating Degree Days in 2006), and (iii) a $4.8 million decrease primarily due to differences in consumption among various customer rate classes. 52 ___________________________________________________________________________________
Other Gas Revenue
Other Gas Revenue decreased by $12.2 million to $50.6 million in 2006 from $62.8 million in 2005 primarily due to lower off-system sales (partially offset in Gas Purchased expense).
Competitive Energy Businesses
Conectiv Energy
The impact of Operating Revenue changes and Fuel and Purchased Energy and Other Services Cost of Sales changes with respect to the Conectiv Energy component of the Competitive Energy business are encompassed within the discussion that follows.
Operating Revenues of the Conectiv Energy segment are derived primarily from the sale of electricity. The primary components of its Costs of Sales are fuel and purchased power. Because fuel and electricity prices tend to move in tandem, price changes in these commodities from period to period can have a significant impact on Operating Revenue and Costs of Sales without signifying any change in the performance of the Conectiv Energy segment. For this reason, PHI from a managerial standpoint focuses on gross margin as a measure of performance.
Conectiv Energy Gross Margin
The following discussion of the results of operations for the Conectiv Energy segment combines as a single business activity designated as "Merchant Generation & Load Service" the activities that in prior reports were designated as "Merchant Generation" and "Full Requirements Load Service." This change has been implemented because Full Requirements Load Service contracts are primarily used, along with other hedges already contained in the prior "Merchant Generation" category, to hedge capacity and energy output from Conectiv Energy's generation plants.
Merchant Generation & Load Service consists primarily of electric power, capacity and ancillary services sales from Conectiv Energy's generating plants; tolling arrangements entered into sell energy and other products from Conectiv Energy's generating plants and to purchase energy and other products from generating plants of other companies; hedges of power, capacity, fuel and load; the sale of excess fuel (primarily natural gas) and emission allowances; electric power, capacity, and ancillary services sales pursuant to competitively bid contracts entered into with affiliated and non-affiliated companies to fulfill their default electricity supply obligations; and fuel switching activities made possible by the multi-fuel capabilities of some of Conectiv Energy's power plants.
In addition, the activity designated as "Other Power, Oil and Gas Marketing Services" in previous reports has been renamed "Energy Marketing". Energy Marketing activities continue to consist primarily of wholesale natural gas and fuel oil marketing; the activities of the real-time power desk, which generates margin by capturing price differences between power pools, and locational and timing differences within a power pool; and prior to October 31, 2006, provided operating services under an agreement with an unaffiliated generating plant. 53 ___________________________________________________________________________________
	December 31,
	2006		2005
Operating Revenue ($ millions):
Merchant Generation & Load Service	$1,347.1		$1,524.4
Energy Marketing	810.2		1,079.2
Total Operating Revenue1	$2,157.3		$2,603.6
Cost of Sales ($ millions):
Merchant Generation & Load Service	$1,116.4		$1,276.3
Energy Marketing	785.6		1,068.1
Total Cost of Sales2	$1,902.0		$2,344.4
Gross Margin($ millions):
Merchant Generation & Load Service	$  230.7	$  248.1
Energy Marketing	24.6	11.1
Total Gross Margin	$  255.3	$  259.2
Generation Fuel and Purchased Power Expenses ($ millions)3:
Generation Fuel Expenses 4,5
Natural Gas	$  161.5	$    95.4
Coal	53.3	46.7
Oil	26.6	104.6
Other6	4.1	4.9
Total Generation Fuel Expenses	$  245.5	$  251.6
Purchased Power Expenses5	$  431.1	$  539.0
Statistics:	2006	2005
Generation Output (MWh):
Base-Load7	1,814,516	1,738,280
Mid-Merit (Combined Cycle)8	2,081,872	2,971,294
Mid-Merit (Oil Fired)9	115,120	694,887
Peaking	131,930	190,688
Tolled Generation	94,064	70,834
Total	4,237,502	5,665,983
Load Service Volume (MWh)10	8,514,719	14,230,888
Average Power Sales Price 11 ($/MWh):
Generation Sales4	$77.69	$87.62
Non-Generation Sales12	$73.79	$53.16
Total	$74.77	$60.12
Average on-peak spot power price at PJM East Hub ($/MWh)13	$65.29	$83.35
Average around-the-clock spot power price at PJM East Hub ($/MWh)13	$53.07	$66.05
Average spot natural gas price at market area M3 ($/MMBtu)14	$  7.31	$  9.69
Weather (degree days at Philadelphia Airport):15
Heating degree days	4,205	4,966
Cooling degree days	1,136	1,306
1Includes $664.1 million and $801.8 million of affiliate transactions for 2006 and 2005, respectively.
2Includes $197.7 million and $217.7 million of affiliate transactions for 2006 and 2005, respectively. Also, excludes depreciation      and amortization expense of $36.3 million and $40.4 million, respectively.
3Consists solely of Merchant Generation & Load Service expenses; does not include the cost of fuel not consumed by the power      plants and intercompany tolling expenses.
4Includes tolled generation.
5 Includes associated hedging gains and losses.
6 Includes emissions expenses, fuel additives, and other fuel-related costs.
7 Edge Moor Units 3 and 4 and Deepwater Unit 6.
8 Hay Road and Bethlehem, all units.
9 Edge Moor Unit 5 and Deepwater Unit 1.
10Consists of all default electricity supply sales; does not include standard product hedge volumes.
11 Calculated from data reported in Conectiv Energy's Electric Quarterly Report (EQR) filed with the FERC; does not include      capacity or ancillary services revenue.
12 Consists of default electricity supply sales, standard product power sales, and spot power sales other than merchant generation as        reported in Conectiv Energy's EQR.
13 Source: PJM website (www.pjm.com).
14 Source: Average delivered natural gas price at Tetco Zone M3 as published in Gas Daily.
15 Source: National Oceanic and Atmospheric Administration National Weather Service data.

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     Conectiv Energy revenue and cost of sales are lower in 2006 primarily due to lower fuel prices and correspondingly lower electricity prices. Lower sales of default electricity supply was a lesser factor.

     Merchant Generation & Load Service gross margin decreased 7%. Milder weather during 2006, coupled with lower spark spreads and an unplanned summer outage at the Hay Road generating facility, resulted in a 26% decrease in output from Conectiv Energy's generating plants. Sales of ancillary services and fuel switching activities contributed less to gross margin in 2006 than in 2005. New higher margin default electricity service contracts (which replaced expiring higher volume, but lower margin default electricity supply sales), a mark-to-market gain on a supply contract, and hedging gains helped reduce the gross margin decrease.

     Energy Marketing gross margins increased $13.5 million in 2006 compared to 2005, primarily due to improved inventory management in the oil marketing business that resulted in a $9.2 million increase and increased gross margins of $7.7 million in the gas marketing business from gains on storage, transportation, and supply contracts. The gross margin increase was partially offset by $3.3 million due to the expiration and associated termination costs of a contract to provide operating services for an unaffiliated generation station which expired on October 31, 2006.

     Pepco Energy Services

     Pepco Energy Services' operating revenue increased $181.4 million primarily due to (i) an increase of $265.6 million due to higher retail electricity customer load in 2006 and (ii) an increase of $44.3 million due to higher energy services project revenue in 2006 resulting from increased construction activity partially offset by lower revenue related to the sale of five businesses in 2006; partially offset by (iii) a decrease of $93.8 million due to lower natural gas volumes in 2006 as a result of fewer customers served and milder weather, (iv) a decrease of $29.0 million due to reduced electricity generation by the Benning and Buzzard power plants in 2006 due to milder weather and higher fuel oil prices, and (v) a decrease of $5.7 million in mass market products and services revenue, a business Pepco Energy Services exited in 2005. As of December 31, 2006, Pepco Energy Services had 3,544 megawatts of commercial and industrial load, as compared to 2,034 megawatts of commerci al and industrial load at the end of 2005. In 2006, Pepco Energy Services' power plants generated 89,578 megawatt hours of electricity as compared to 237,624 in 2005.

     Other Non-Regulated

     Other Non-Regulated revenue increased $6.1 million to $90.6 million in 2006 from $84.5 million in 2005. Operating revenues consist of lease earnings recognized under Statement of Financial Accounting Standards (SFAS) No. 13 and changes to the carrying value of the other miscellaneous investments.

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:

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	2006		2005		Change
Power Delivery	$	3,303.6	$	2,720.5	$	583.1
Conectiv Energy		1,902.0		2,344.4		(442.4)
Pepco Energy Services		1,531.1		1,357.5		173.6
Corp. & Other		(670.8)		(810.4)		139.6
Total	$	6,065.9	$	5,612.0	$	453.9

     Power Delivery Business

     Power Delivery's Fuel and Purchased Energy costs associated with Default Electricity Supply sales increased by $583.1 million primarily due to: (i) $736.8 million increase in average energy costs, resulting from higher costs of Default Electricity Supply contracts that went into effect primarily in June 2006 and 2005, offset by (ii) $155.5 million decrease primarily due to differences in consumption among the various customer rate classes (impact due to such factors as weather, migration, etc).

     Competitive Energy Business

     Conectiv Energy

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

     Pepco Energy Services

     Pepco Energy Services' Fuel and Purchased Energy and Other Services Cost of Sales increased $173.6 million due to (i) a $246.5 million increase in purchases of electricity in 2006 to serve higher retail customer load and (ii) an increase of $37.2 million in costs due to higher energy services projects in 2006 as a result of increased construction activity; partially offset by (iii) a decrease of $87.6 million for purchases of natural gas due to lower volumes sold in 2006 as the result of fewer customers served and milder weather, (iv) a $17.6 million decrease in electricity generation costs in 2006 due to reduced electricity generation by the Benning and Buzzard power plants as a result of milder weather and higher fuel oil prices, (v) a $4.9 million decrease in mass market products and services costs, a business Pepco Energy Services exited in 2005, and (vi) decreased costs due to the sale of five companies in 2006.

     Other Operation and Maintenance

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

	2006		2005		Change
Power Delivery	$	639.6	$	643.1	$	(3.5)
Conectiv Energy		116.3		107.7		8.6
Pepco Energy Services		67.6		71.2		(3.6)
Other Non-Regulated		4.2		5.2		(1.0)
Corp. & Other		(20.4)		(11.5)		(8.9)
Total	$	807.3	$	815.7	$	(8.4)

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     The higher operation and maintenance expenses of the Conectiv Energy segment were primarily due to planned and unplanned facility outages. The impact of this increase was substantially offset by lower corporate expenses related to the amortization of non-compete agreements and other administrative and general expenses.

     Depreciation and Amortization

     Depreciation and amortization expenses decreased by $14.1 million to $413.2 million in 2006, from $427.3 million in 2005. The decrease is primarily due to (i) a $5.4 million change in depreciation technique resulting from the ACE distribution base rate case settlement in 2005 that depreciates assets over their whole life versus their remaining life, (ii) a $4.1 million reduction of ACE regulatory debits, and (iii) a $3 million reduction due to completion of amortization related to software, offset by net increases to plant in-service (adds less retirements) of about $5.4 million.

     Deferred Electric Service Costs

     Deferred Electric Service Costs decreased by $98.1 million to $22.1 million in 2006, from $120.2 million in 2005. The $98.1 million decrease was attributable to (i) $92.4 million net under-recovery associated with New Jersey BGS, NUGs, market transition charges and other restructuring items and (ii) $5.7 million in regulatory disallowances (net of amounts previously reserved) in connection with the ACE distribution base rate case settlement in 2005. At December 31, 2006, ACE's balance sheet included as a regulatory liability an over-recovery of $164.9 million with respect primarily to these items, which is net of a $46.0 million reserve for items disallowed by the New Jersey Board of Public Utilities (NJBPU) in a ruling that is under appeal. The $164.9 million regulatory liability also includes an $81.3 million gain related to the September 1, 2006 sale of ACE's interests in Keystone and Conemaugh.

     Impairment Losses

     For the year ended December 31, 2006, Pepco Holdings recorded pre-tax impairment losses of $18.9 million ($13.7 million after-tax) related to certain energy services business assets owned by Pepco Energy Services. The impairments were recorded as a result of the execution of contracts to sell certain assets and due to the lower than expected production and related estimated cash flows from other assets. The fair value of the assets under contracts for sale was determined based on the sales contract price, while the fair value of the other assets was determined by estimating future expected production and cash flows.

     Gain on Sales of Assets

     Pepco Holdings recorded a Gain on Sales of Assets of $.8 million for the year ended December 31, 2006, compared to $86.8 million for the year ended December 31, 2005. The $86.8 million gain in 2005 primarily consisted of: (i) a $68.1 million gain from the sale of non-utility land owned by Pepco located at Buzzard Point in the District of Columbia, and (ii) a $13.3 million gain recorded by PCI from proceeds related to the final liquidation of a financial investment that was written off in 2001.

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     Gain on Settlement of Claims with Mirant

     The Gain on Settlement of Claims with Mirant of $70.5 million in 2005 represents a settlement (net of customer sharing) with Mirant of the Pepco TPA Claim ($70 million gain) and a Pepco asbestos claim against the Mirant bankruptcy estate ($.5 million gain). See "Regulatory and Other Matters - Relationship with Mirant Corporation" for additional information.

Other Income (Expenses)

     Other Expenses (which are net of other income) decreased by $3.1 million to $282.4 million for the year ended December 31, 2006 from $285.5 million for the same period in 2005. The decrease primarily resulted from an increase in income from equity fund valuations at PCI of $7.3 million and $2.3 in lower impairment charges during 2006 compared to 2005, partially offset by a $6.6 million gain in 2005 related to the sale of an investment.

Income Tax Expense

     Pepco Holdings' effective tax rate for the year ended December 31, 2006 was 39% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit), and the flow-through of certain book/tax depreciation differences, partially offset by the flow-through of Deferred Investment Tax Credits and tax benefits related to certain leveraged leases.

     Pepco Holdings' effective tax rate for the year ended December 31, 2005 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 under audit, and the flow-through of certain book/tax depreciation differences, partially offset by the flow-through of Deferred Investment Tax Credits and tax benefits related to certain leveraged leases.

     The following results of operations discussion is for the year ended December 31, 2005, compared to the year ended December 31, 2004. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

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

	2005		2004		Change
Power Delivery	$	4,702.9	$	4,377.7	$	325.2
Conectiv Energy		2,603.6		2,409.8		193.8
Pepco Energy Services		1,487.5		1,166.6		320.9
Other Non-Regulated		84.5		90.5		(6.0)
Corporate and Other		(813.0)		(821.5)		8.5
Total Operating Revenue	$	8,065.5	$	7,223.1	$	842.4

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     Power Delivery Business

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

	2005		2004		Change
Regulated T&D Electric Revenue	$	1,623.2	$	1,566.6	$	56.6
Default Supply Revenue		2,753.0		2,514.7		238.3
Other Electric Revenue		65.2		67.8		(2.6)
Total Electric Operating Revenue		4,441.4		4,149.1		292.3
Regulated Gas Revenue		198.7		169.7		29.0
Other Gas Revenue		62.8		58.9		3.9
Total Gas Operating Revenue		261.5		228.6		32.9
Total Power Delivery Operating Revenue	$	4,702.9	$	4,377.7	$	325.2

Electric Operating Revenue

Regulated T&D Electric Revenue	2005		2004		Change
Residential	$	613.0	$	597.7	$	15.3
Commercial		726.8		692.3		34.5
Industrial		36.8		37.4		(.6)
Other (Includes PJM)		246.6		239.2		7.4
Total Regulated T&D Electric Revenue	$	1,623.2	$	1,566.6	$	56.6

Regulated T&D Electric Sales (Gwh)	2005		2004		Change
Residential		18,045		17,759		286
Commercial		29,441		28,448		993
Industrial		4,288		4,471		(183)
Total Regulated T&D Electric Sales		51,774		50,678		1,096

Regulated T&D Electric Customers (000s)	2005		2004		Change
Residential		1,591		1,567		24
Commercial		196		193		3
Industrial		2		2		-
Total Regulated T&D Electric Customers		1,789		1,762		27

     Regulated T&D Revenue increased by $56.6 million primarily due to the following: (i) $19.3 million due to customer growth, the result of a 1.5% customer increase in 2005, (ii) $17.6 million increase as a result of a 14.7% increase in Cooling Degree Days in 2005, (iii) $1.9 million (including $3.3 million in tax pass-throughs) increase due to net adjustments for estimated unbilled revenues recorded in the second and fourth quarters of 2005, reflecting a modification in the estimation process, primarily reflecting higher estimated power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers) and (iv) $21.7 million increase in tax pass-throughs, principally a county surcharge (offset in Other Taxes) offset by (v) $8.6 million other sales and rate variances.

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     Default Electricity Supply

Default Supply Revenue	2005		2004		Change
Residential	$	1,161.7	$	993.6	$	168.1
Commercial		994.9		1,060.9		(66.0)
Industrial		134.2		140.7		(6.5)
Other (Includes PJM)		462.2		319.5		142.7
Total Default Supply Revenue	$	2,753.0	$	2,514.7	$	238.3

Default Electricity Supply Sales (Gwh)	2005		2004		Change
Residential		17,490		16,775		715
Commercial		15,020		19,203		(4,183)
Industrial		2,058		2,292		(234)
Other		157		226		(69)
Total Default Electricity Supply Sales		34,725		38,496		(3,771)

Default Electricity Supply Customers (000s)	2005		2004		Change
Residential		1,557		1,509		48
Commercial		181		178		3
Industrial		2		2		-
Other		2		2		-
Total Default Electricity Supply Customers		1,742		1,691		51

     Default Supply Revenue increased $238.3 million primarily due to the following: (i) $251.9 million due to higher retail energy rates, the result of market-based SOS competitive bid procedures implemented in Maryland in June 2005 and the District of Columbia in February 2005, (ii) $142.2 million increase in wholesale energy revenues resulting from sales of generated and purchased energy into PJM due to higher market prices in 2005, (iii) $44.8 million due to weather (15% increase in Cooling Degree Days), (iv) $48.2 million increase due to customer growth, and (v) $8.1 million due to other sales and rate variances, offset by (vi) $245.0 million decrease due primarily to higher commercial customer migration, and (vii) $11.9 million decrease due to net adjustments for estimated unbilled revenues recorded in the second and fourth quarters of 2005, primarily reflecting higher estimated power line losses (estimates of electricity expected to be lost in the process of its transm ission and distribution to customers).

     Other Electric Revenue decreased $2.6 million to $65.2 million from $67.8 million in 2004 primarily due to mutual assistance work related to storm damage in 2005 (offset in Other Operations and Maintenance expense).

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     Gas Operating Revenue

Regulated Gas Revenue	2005		2004		Change
Residential	$	115.0	$	100.2	$	14.8
Commercial		68.5		56.7		11.8
Industrial		10.6		8.3		2.3
Transportation and Other		4.6		4.5		.1
Total Regulated Gas Revenue	$	198.7	$	169.7	$	29.0

Regulated Gas Sales (Bcf)	2005		2004		Change
Residential		8.4		8.7		(.3)
Commercial		5.6		5.5		.1
Industrial		1.1		1.2		(.1)
Transportation and Other		5.6		6.2		(.6)
Total Regulated Gas Sales		20.7		21.6		(.9)

Regulated Gas Customers (000s)	2005		2004		Change
Residential		111		109		2
Commercial		9		9		-
Industrial		-		-		-
Transportation and Other		-		-		-
Total Regulated Gas Customers		120		118		2

     Regulated Gas Revenue increased by $29.0 million primarily due to a $30.6 million increase in the GCR effective November 2004 and 2005, due to higher natural gas commodity costs.

     Other Gas Revenue increased by $3.9 million to $62.8 million from $58.9 in 2004 primarily due to increased capacity release revenues.

     Competitive Energy Businesses

     Conectiv Energy

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

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     Conectiv Energy Gross Margin

	December 31,
	2005	2004
Operating Revenue ($ millions):
Merchant Generation & Load Service	$1,524.4	$1,644.7
Energy Marketing	1,079.2	765.1
Total Operating Revenue1	$2,603.6	$2,409.8
Cost of Sales ($ millions):
Merchant Generation & Load Service	$1,276.3	$1,377.4
Energy Marketing	1,068.1	753.5
Total Cost of Sales2	$2,344.4	$2,130.9
Gross Margin($ millions):
Merchant Generation & Load Service	$   248.1	$   267.3
Energy Marketing	11.1	11.6
Total Gross Margin	$   259.2	$   278.9
Generation Fuel & Purchased Power Expenses($ millions)3:
Generation Fuel Expenses 4, 5
Natural Gas	$     95.4	$       6.5
Coal	46.7	41.8
Oil	104.6	53.6
Other6	4.9	4.4
Total Generation Fuel Expenses	$   251.6	$   106.3
Purchased Power Expenses 5	$   539.0	$   940.8
Statistics:
Generation Output (MWh):
Base-Load7	1,738,280	1,854,065
Mid-Merit (Combined Cycle)8	2,971,294	2,634,749
Mid-Merit (Oil Fired)9	694,887	523,085
Peaking	190,688	149,784
Tolled Generation	70,834	-
Total	5,665,983	5,161,683
Load Service Volume (MWh)10	14,230,888	15,243,402
Average Power Sales Price11 ($/MWh):
Generation Sales4	$87.62	$50.45
Non-Generation Sales12	$53.16	$43.03
Total	$60.12	$45.60
Average on-peak spot power price at PJM East Hub ($/MWh)13	$83.35	$55.22
Average around-the-clock spot power price at PJM East Hub ($/MWh)13	$66.05	$45.86
Average spot natural gas price at market area M3 ($/MMBtu)14	$  9.69	$  6.63
Weather (degree days at Philadelphia Airport)15:
Heating degree days	4,966	4,885
Cooling degree days	1,306	1,049
1Includes $801.8 million and $820.3 million of affiliate transactions for 2005 and 2004, respectively.
2Includes $217.7 million and $245.4 million of affiliate transactions for 2005 and 2004, respectively. Also, excludes depreciation        and amortization expense of $40.4 million and $45.2 million, respectively.
3 Consists solely of Merchant Generation & Load Service expenses; does not include the cost of fuel not consumed       by the power plants and inter-company tolling expenses.
4Includes tolled generation.
5 Includes associated hedging gains and losses.
6 Includes emissions expenses, fuel additives, and other fuel-related costs.
7Edge Moor Units 3 & 4 and Deepwater Unit 6.
8 Hay Road and Bethlehem, all units.
9 Edge Moor Unit 5 and Deepwater Unit 1
10Consists of all default electricity supply sales; does not include standard product hedge volumes.
11 Calculated from data reported in Conectiv Energy's Electric Quarterly Report (EQR) filed with the FERC; does not include        capacity or ancillary services revenues.
12 Consists of default electricity supply sales, standard product power sales, and spot power sales other than merchant generation        as reported in Conectiv's EQR.
13 Source: PJM Interconnection, LLC website (www.pjm.com)
14 Source: Average delivered natural gas price at Tetco Zone M3 as published in Gas Daily.
15 Source: National Oceanic and Atmospheric Administration National Weather Service data.

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     Merchant Generation & Load Service experienced a 7% decline in gross margin. Higher fuel and energy prices in 2005 resulted in costlier load service and negative hedge results. This was partially offset by a 10% increase in Merchant Generation output primarily driven by warmer weather during the summer months of 2005 and continued PJM load growth.

     Energy Marketing margins decreased because of a one-time gain of $8.7 million on a group of coal contracts in 2004. This was partially offset by higher margin sales for oil marketing ($5.6 million) and gas marketing ($2.0 million) during the fourth quarter of 2005.

     Pepco Energy Services

     The increase in Pepco Energy Services' operating revenue of $320.9 million is primarily due to (i) an increase of $228.1 million due to commercial and industrial retail load acquisition by Pepco Energy Services in 2005 at higher prices than in 2004, (ii) an increase of $39.3 million due to higher generation from its Benning and Buzzard Point power plants in 2005 due to warmer weather conditions, and (iii) an increase of $49.5 million due to higher energy services activities in 2005 resulting from contracts signed with customers under which Pepco Energy Services provides services for energy efficiency and high voltage installation projects. As of December 31, 2005, Pepco Energy Services had 2,034 megawatts of commercial and industrial load, as compared to 1,663 megawatts of commercial and industrial load at the end of 2004. In 2005, Pepco Energy Services' power plants generated 237,624 megawatt hours of electricity as compared to 45,836 in 2004.

Operating Expenses

     Fuel and Purchased Energy and Other Services Cost of Sales

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

	2005		2004		Change
Power Delivery	$	2,720.5	$	2,524.2	$	196.3
Conectiv Energy		2,344.4		2,130.9		213.5
Pepco Energy Services		1,357.5		1,064.4		293.1
Corporate and Other		(810.4)		(829.0)		18.6
Total	$	5,612.0	$	4,890.5	$	721.5

     Power Delivery Business

     Power Delivery's Fuel and Purchased Energy costs increased by $196.3 million primarily due to (i) $326.7 million increase for higher average energy costs resulting from Default Electricity Supply contracts implemented in 2005, (ii) $65.6 million increase due to customer growth, (iii) $33.1 million increase for gas commodity purchases, (iv) $25.8 million increase in other sales and rate variances, offset by (v) $254.9 million decrease due to higher customer migration. This expense is primarily offset in Default Supply Revenue.

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     Conectiv Energy

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

     Pepco Energy Services

     Pepco Energy Services' fuel and purchased energy and other services cost of sales increased $293.1 million due to (i) higher volumes of electricity purchased at higher prices in 2005 to serve commercial and industrial retail customers, (ii) higher fuel and operating costs for the Benning and Buzzard Point power plants in 2005 due to higher electric generation that resulted from warmer weather in 2005, and (iii) higher energy services activities in 2005 resulting from contracts signed with customers under which Pepco Energy Services provides services for energy efficiency and high voltage installation projects.

     Other Operation and Maintenance

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

	2005		2004		Change
Power Delivery	$	643.1	$	623.9	$	19.2
Conectiv Energy		107.7		103.8		3.9
Pepco Energy Services		71.2		71.5		(.3)
Other Non-Regulated		5.2		4.6		.6
Corporate and Other		(11.5)		(7.2)		(4.3)
Total	$	815.7	$	796.6	$	19.1

     PHI's other operation and maintenance increased by $19.1 million to $815.7 million for the year ended 2005 from $796.6 million for the year ended 2004 primarily due to the following: (i) a $10.3 million increase in employee related costs, (ii) $9.0 million increase in corporate services allocation, (iii) $3.9 million increase due to the write-off of software, (iv) $3.2 million increase due to mutual assistance work related to storm damage in 2005 (offset in Other Electric Revenues), and (v) $2.1 million increase in maintenance expenses, partially offset by (vi) $4.9 million reduction in the uncollectible account reserve to reflect the amount expected to be collected on unpaid obligations of Mirant to Pepco existing at the time of filing of Mirant's bankruptcy petition consisting primarily of payments due Pepco with respect to Mirant's obligations to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under a power purchase agreement with Panda-Bran dywine, L.P. and (vii) a $5.5 million decrease in PJM administrative expenses.

     Depreciation and Amortization

     PHI's depreciation and amortization expenses decreased by $18.9 million to $427.3 million in 2005 from $446.2 million in 2004. The decrease is primarily due to a $7.6 million decrease from a change in depreciation technique resulting from a 2005 final rate order from the NJBPU and a $4.8 million decrease due to a change in the estimated useful lives of Conectiv Energy's generation assets.

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     Other Taxes

     Other taxes increased by $30.8 million to $342.2 million in 2005 from $311.4 million in 2004 due to higher pass-throughs, mainly as the result of a county surcharge rate increase (primarily offset in Regulated T&D Electric Revenue).

     Deferred Electric Service Costs

     Deferred Electric Service Costs, which relates only to ACE, increased by $83.9 million to $120.2 million in 2005, from $36.3 million in 2004. At December 31, 2005, DESC represents the net expense or over-recovery associated with New Jersey NUGs, market transition change and other restructuring items. The $83.9 million increase represents (i) $77.1 million net over-recovery associated with New Jersey BGS, NUGs, market transition charges and other restructuring items, and (ii) $4.5 million in regulatory disallowances (net of amounts previously reserved) associated with the April 2005 NJBPU settlement agreement. ACE's rates for the recovery of those costs are reset annually and the rates will vary from year to year. At December 31, 2005, ACE's balance sheet included as a regulatory liability an over-recovery of $40.9 million with respect to these items, which is net of a $47.3 million reserve for items disallowed by the NJBPU in a ruling that is under appeal.

     Gain on Sales of Assets

     Pepco Holdings recorded a Gain on Sales of Assets of $86.8 million for the year ended December 31, 2005, compared to $30.0 million for the year ended December 31, 2004. The $86.8 million gain in 2005 primarily consists of: (i) a $68.1 million gain from the 2005 sale of non-utility land owned by Pepco located at Buzzard Point in the District of Columbia, and (ii) a $13.3 million gain recorded by PCI from proceeds related to the final liquidation of a financial investment that was written off in 2001. The $30.0 million gain in 2004 consists of: (i) a $14.7 million gain from the 2004 condemnation settlement with the City of Vineland relating to the transfer of ACE's distribution assets and customer accounts to the city, (ii) a $6.6 million gain from the 2004 sale of land, and (iii) an $8.3 million gain on the 2004 sale of aircraft investments by PCI.

     Gain on Settlement of Claims with Mirant

     The Gain on Settlement of Claims with Mirant of $70.5 million in 2005 represents a settlement (net of customer sharing) with Mirant of the Pepco TPA Claim ($70 million gain) and a Pepco asbestos claim against the Mirant bankruptcy estate ($.5 million gain). See "Regulatory and Other Matters - Relationship with Mirant Corporation" for additional information.

Other Income (Expenses)

     Other expenses (which are net of other income) decreased by $55.9 million to $285.5 million in 2005 from $341.4 million in 2004, primarily due to the following: (i) a decrease in net interest expense of $35.7 million, which primarily resulted from a $23.6 million decrease due to less debt outstanding during the 2005 period and a decrease of $12.8 million of interest expense that was recorded by Conectiv Energy in 2004 related to costs associated with the prepayment of debt related to the Bethlehem mid-merit facility, (ii) an $11.2 million impairment charge on the Starpower investment that was recorded during 2004, (iii) income of $7.9 million received by PCI in 2005 from the sale and liquidation of energy investments, and (iv) income of $3.9 million

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in 2005 from cash distributions from a joint-owned cogeneration facility, partially offset by (v) an impairment charge of $4.1 million in 2005 related to a Conectiv Energy investment in a jointly owned generation project, and (vi) a pre-tax gain of $11.2 million on the distribution of a cogeneration joint venture that was recognized by Conectiv Energy during the second quarter of 2004.

Income Tax Expense

     Pepco Holdings' effective tax rate for the year ended December 31, 2005 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 under audit and the flow-through of certain book/tax depreciation differences, partially offset by the flow-through of Deferred Investment Tax Credits and tax benefits related to certain leveraged leases.

     Pepco Holdings' effective tax rate for the year ended December 31, 2004 was 39% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit), the flow-through of certain book/tax depreciation differences, and the settlement with the IRS on certain non-lease financial assets, partially offset by the flow-through of Deferred Investment Tax Credits, 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.

Extraordinary Item

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

CAPITAL RESOURCES AND LIQUIDITY

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

Working Capital

     At December 31, 2006, Pepco Holdings' current assets on a consolidated basis totaled $2.0 billion and its current liabilities totaled $2.5 billion. At December 31, 2005, Pepco Holdings' current assets on a consolidated basis totaled $2.1 billion and its current liabilities totaled $2.4 billion.

     PHI's working capital deficit results primarily 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 billed to customers. Short-term financing is used to meet liquidity needs. Short-term financing is also used, at times, to temporarily fund redemptions of long-term debt, until long-term replacement financings are completed.

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     At December 31, 2006, Pepco Holdings' cash and cash equivalents and its restricted cash totaled $60.8 million, none of which was net cash collateral held by subsidiaries of PHI engaged in Competitive Energy or Default Electricity Supply activities. At December 31, 2005, Pepco Holdings' cash and cash equivalents and its restricted cash, totaled $144.5 million. Of the 2005 total, $112.8 million consisted of net cash collateral held by subsidiaries of PHI engaged in Competitive Energy and Default Electricity Supply activities (none of which was held as restricted cash). See "Capital Requirements -- Contractual Arrangements with Credit Rating Triggers or Margining Rights" for additional information.

     A detail of PHI's short-term debt balance and its current maturities of long-term debt and project funding balance follows. Current maturities of long-term debt may be temporarily funded with short-term financing until long-term replacement financings are completed.

	As of December 31, 2006 (Millions of dollars)
Type	PHI Parent	Pepco	DPL	ACE	ACE Funding	Conectiv Energy	PES	PCI	Conectiv	PHI Consolidated
Variable Rate   Demand Bonds	$        -	$        -	$104.8	$22.6	$        -	$        -	$26.8	$      -	$        -	$154.2
Commercial Paper	36.0	67.1	91.1	1.2	-	-	-	-	-	195.4
Total Short-Term Debt	$  36.0	$  67.1	$195.9	$23.8	$        -	$        -	$26.8	$      -	$        -	$349.6
Current Maturities   of Long-Term Debt   and Project Funding	$500.0	$210.0	$  64.7	$16.0	$29.9	$        -	$  2.6	$34.3	$        -	$857.5

	As of December 31, 2005 (Millions of dollars)
Type	PHI Parent	Pepco	DPL	ACE	ACE Funding	Conectiv Energy	PES	PCI	Conectiv	PHI Consolidated
Variable Rate   Demand Bonds	$    -	$    -	$104.8	$22.6	$     -	$  -	$29.0	$   -	$    -	$156.4
Commercial Paper	-	-	-	-	-	-	-	-	-	-
Total Short-Term Debt	$    -	$    -	$104.8	$22.6	$     -	$  -	$29.0	$   -	$    -	$156.4
Current Maturities   of Long-Term Debt   and Project Funding	$300.0	$50.0	$ 22.9	$65.0	$29.0	$  -	$ 2.6	$   -	$    -	$469.5

Cash Flow Activity

     PHI's cash flows for 2006, 2005, and 2004 are summarized below.

	Cash (Use) Source
	2006	2005	2004
	(Millions of dollars)
Operating Activities	$ 202.6	$986.9	$715.7
Investing Activities	(229.1)	(333.9)	(417.3)
Financing Activities	(46.2)	(561.0)	(359.1)
Net (decrease) increase in cash and cash equivalents	$(72.7)	$ 92.0	$(60.7)

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     Operating Activities

     Cash flows from operating activities are summarized below for 2006, 2005, and 2004.

	Cash Source (Use)
	2006	2005	2004
	(Millions of dollars)
Net Income	$248.3	$371.2	$260.6
Non-cash adjustments to net income	543.0	48.3	527.6
Changes in working capital	(588.7)	567.4	(72.5)
Net cash from operating activities	$202.6	$986.9	$715.7

     Net cash from operating activities decreased by $784.3 million for the year ended December 31, 2006 compared to 2005. In addition to the decrease in net income, the factors contributing to the decrease in cash flow from operating activities included: (i) an increase of $194.5 million in taxes paid in 2006, including a tax payment of $121 million made in February 2006 (see "Regulatory and Other Matters -- IRS Mixed Service Cost Issue" below), (ii) a decrease in the change in regulatory assets and liabilities of $107.9 million due primarily to the 2005 over-recoveries associated with New Jersey BGS, NUGs, market transition charges and other restructuring items, and (iii) the collateral requirements associated with the activities of Competitive Energy, which in 2006 required the net posting of cash collateral with third parties, whereas in 2005 PHI was a net holder of net cash collateral.

     Changes in cash collateral include the following:

· The balance of net cash collateral held by PHI was $112.8 million as of December 31, 2005. As of December 31, 2006, Competitive Energy activities and Default Electricity Supply purchase agreements of PHI's utility subsidiaries required the posting by PHI of cash collateral in the amount of $99.0 million (a total decrease of $211.8 million).

· The balance of net cash collateral held by PHI increased from $21.4 million as of December 31, 2004, to $112.8 million as of December 31, 2005 (a total increase of $91.4 million).

     Net cash from operating activities increased by $271.2 million in 2005 as compared to 2004. A $110.6 million increase in net income in 2005 as compared to 2004 is a result of improved operating results at PHI's regulated utilities. Other factors contributing to the increases in cash flow from operating activities include the following: (i) Pepco's receipt of $112.9 million in proceeds in December 2005 for the sale of the Pepco TPA Claim and the Pepco asbestos claim against the Mirant bankruptcy estate, (ii) a decrease of approximately $29 million in interest paid on debt obligations in 2005 as compared to 2004 due to a decrease in outstanding debt, (iii) an increase in power broker payables in 2005 as a result of higher electricity prices, and (iv) an increase from $21.4 million to $112.8 million in the cash collateral held in connection with Competitive Energy activities.

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     Investing Activities

     Cash flows used by investing activities during 2006, 2005, and 2004 are summarized below.

	Cash (Use) Source
	2006	2005	2004
	(Millions of dollars)
Construction expenditures	$(474.6)	$(467.1)	$(517.4)
Cash proceeds from sale of:
Starpower investment	-	-	29.0
Marketable securities, net	-	-	19.4
Office building and other properties	181.5	84.1	46.4
All other investing cash flows, net	64.0	49.1	5.3
Net cash used by investing activities	$(229.1)	$(333.9)	$(417.3)

     Net cash used by investing activities decreased $104.8 million for the year ended December 31, 2006 compared to 2005. The decrease is primarily due to the net proceeds received of $177.0 million related to the sale of ACE's ownership share of the Keystone and Conemaugh generating plants, offset by the $73.7 million in proceeds related to the 2005 sale of Buzzard Point land.

     Net cash used by investing activities decreased by $83.4 million in 2005 compared to 2004. The decrease is primarily due to a $50.3 million decrease in construction expenditures, net proceeds of $73.7 million related to the 2005 sale of Buzzard Point land, and proceeds of $33.8 million received by PCI from the sale of an energy investment and from the final liquidation of a financial investment that was written off in 2001. In 2004, PHI sold its 50% interest in Starpower for $29 million in cash. Additionally in 2004, PCI continued to liquidate its marketable securities portfolio and PHI received proceeds from the sale of aircraft and land.

     Financing Activities

     Cash flows used by financing activities during 2006, 2005 and 2004 are summarized below.

	Cash (Use) Source
	2006	2005	2004
	(Millions of dollars)
Dividends paid on common and preferred stock	$  (199.5)	$  (191.4)	$  (178.8)
Common stock issued through the Dividend     Reinvestment Plan (DRP)	29.8	27.5	29.2
Issuance of common stock	17.0	5.7	288.8
Redemption of preferred stock of subsidiaries	(21.5)	(9.0)	(53.3)
Issuances of long-term debt	514.5	532.0	650.4
Reacquisition of long-term debt	(578.0)	(755.8)	(1,214.7)
Issuances (repayments) of short-term debt, net	193.2	(161.3)	136.3
All other financing cash flows, net	(1.7)	(8.7)	(17.0)
Net cash used by financing activities	$  (46.2)	$  (561.0)	$  (359.1)

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     Net cash used by financing activities decreased $514.8 million for the year ended December 31, 2006 compared to the same period in 2005.

     Preferred stock redemptions in 2006 consisted of Pepco's $21.5 million redemption in March 2006 of the following securities:

· 216,846 shares of its $2.44 Series, 1957 Serial Preferred Stock,

· 99,789 shares of its $2.46 Series, 1958 Serial Preferred Stock, and

· 112,709 shares of its $2.28 Series, 1965 Serial Preferred Stock.

     On May 15, 2006, Pepco used the proceeds from a bond refinancing to redeem an aggregate of $109.5 million of three series of first mortgage bonds. The series were combined into one series of $109.5 million due 2022.

     In December 2006, Pepco retired at maturity $50 million of variable rate notes.

     On June 1, 2006, DPL redeemed $2.9 million of 6.95% first mortgage bonds due 2008.

     In October 2006, DPL retired at maturity $20 million of medium-term notes.

     In December 2006, DPL issued $100 million of 5.22% unsecured notes due 2016. The proceeds were used to redeem DPL's commercial paper outstanding.

     In the first quarter of 2006, PHI retired at maturity $300 million of its 3.75% unsecured notes with proceeds from the issuance of commercial paper.

     In December 2006, PHI issued $200 million of 5.9% unsecured notes due 2016. The net proceeds, plus additional funds, were used to repay a $250 million bank loan entered into in August 2006.

     In January 2006, ACE retired at maturity $65 million of medium-term notes.

     On March 15, 2006, ACE issued $105 million of Senior Notes due 2036. The proceeds were used to pay down short-term debt incurred earlier in the quarter to repay medium-term notes at maturity.

     For the year ended December 31, 2006, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $20.7 million on Series 2002-1 Bonds, Class A-1 and $8.3 million on Series 2003-1, Class A-1 with a weighted average interest rate of 2.89%.

     All of the $514.5 million in issuances of long-term debt for the year ended December 31, 2006, are discussed above. Additionally, $576.4 million of the total $578.0 million in reacquisitions of long-term debt for the year ended December 31, 2006 are discussed above.

     In 2006, Pepco and DPL issued short-term debt of $67.1 million and $91.1 million, respectively, in order to cover capital expenditures and tax obligations throughout the year.

     Net cash used by financing activities increased by $201.9 million in 2005 as compared to 2004.

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     Common stock dividend payments were $198.3 million in 2006, $188.9 million in 2005 and $176.0 million in 2004. The increase in common dividends paid in 2005 was due primarily to an offering of 14,950,000 shares of common stock in September 2004 and an issuance of 1,228,505 shares in 2005, under the DRP. The increase in common dividends paid in 2006 was due to the issuance of 1,232,569 shares under the DRP and a quarterly dividend increase from 25 cents per share to 26 cents per share in the first quarter of 2006.

     Preferred stock redemptions in 2005 totaled $9.0 million and included the following:

· in October 2005, Pepco redeemed 22,795 shares of its $2.44 Series 1957 Serial Preferred Stock at $1.1 million, 74,103 shares of its $2.46 Series 1958 Serial Preferred Stock at $3.7 million, and 13,148 shares of its $2.28 Series 1965 Serial Preferred Stock at $.7 million

· in August 2005, ACE redeemed 160 shares of its 4.35% Serial Preferred Stock at $.02 million, and in December 2005, DPL redeemed all of the 35,000 shares of its 6.75% Serial Preferred Stock outstanding at $3.5 million.

     In 2005, Pepco Holdings issued $250 million of floating rate unsecured notes due 2010. The net proceeds, plus additional funds, were used to repay commercial paper issued to fund the $300 million redemptions of Conectiv debt.

     In September 2005, Pepco used the proceeds from the June 2005 issuance of $175 million in senior secured notes to fund the retirement of $100 million in first mortgage bonds at maturity as well as the redemption of $75 million in first mortgage bonds prior to maturity.

     In 2005, DPL issued $100 million of unsecured notes due 2015. The net proceeds were used to redeem $102.7 million of higher rate securities.

     In December 2005, Pepco paid down $50 million of its $100 million bank loan due December 2006.

     In 2005, ACE retired at maturity $40 million of medium-term notes.

     In 2005, PCI redeemed $60 million of Medium-Term Notes.

     Described above are $525 million of the $532 million total 2005 long-term debt issuances and $727.7 million of the $755.8 million total 2005 reacquisition of long-term debt.

     In 2005, ACE and PHI redeemed a total of $161.3 million in short-term debt with cash from operations.

     As a result of the 2004 common stock issuance, Pepco Holdings received $278.5 million of proceeds, net of issuance costs of $10.3 million. The proceeds in combination with short-term debt were used to prepay in its entirety the $335 million Conectiv Bethlehem term loan.

     In 2004, Pepco redeemed all of the 900,000 shares of $3.40 series mandatorily redeemable preferred stock then outstanding for $45 million and 165,902 shares of $2.28 series preferred stock for $8.3 million.

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     In 2004, Pepco Holdings redeemed $200 million of variable rate notes at maturity.

     In 2004, Pepco issued $275 million of secured senior notes with maturities of 10 and 30 years, the net proceeds of which were used to redeem higher interest rate securities of $210 million 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, the net proceeds of which 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 of secured senior notes which mature in 2029 and 2034, respectively; the net proceeds of $173.2 million were used to redeem higher interest rate securities. Conectiv redeemed $50 million of Medium-Term Notes, and PCI redeemed $86 million of Medium-Term Notes in 2004. In 2004, redemptions of mandatorily redeemable trust preferred securities included $70 m illion for DPL and $25 million for ACE.

     Described above are $649.7 million of the $650.4 million total 2004 long-term debt issuances and $1,149.2 million of the $1,214.7 million total 2004 reacquisition of long-term debt.

     PHI's long-term debt is subject to certain covenants. PHI and its subsidiaries are in compliance with all requirements.

Subsequent Financing Activities

     On November 17, 2006, certain institutional buyers tentatively agreed to purchase in April 2007, in a private placement, $200 million of Pepco Holdings unsecured notes having an interest rate of 6% and a term of twelve years. PHI intends to use the proceeds to repay a like amount of outstanding long-term debt.

     On January 18, 2007, DPL redeemed all outstanding shares of its Serial Preferred Stock of each series at redemption prices ranging from 103% to 105% of par, for an aggregate redemption price of $18.9 million.

Sales of ACE Generating Facilities

     As discussed in Note (12), Commitments and Contingencies, on September 1, 2006, ACE completed the sale of its interest in the Keystone and Conemaugh generating facilities for approximately $177.0 million, which was subsequently decreased by $1.6 million based on a post-closing 60-day true up for applicable items not known at the time of closing.

     Additionally, on February 8, 2007, ACE completed the sale of the B.L. England generating facility for a price of $9.0 million, subject to adjustment.

Sale of Interest in Cogeneration Joint Venture

     During the first quarter of 2006, Conectiv Energy recognized a $12.3 million pre-tax gain ($7.9 million after-tax) on the sale of its equity interest in a joint venture which owns a wood burning cogeneration facility in California.

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Proceeds from Settlement of Claims with Mirant

     In December 2005, Pepco received proceeds of $112.9 million for the sale of the Pepco TPA Claim and the Pepco asbestos claim against the Mirant bankruptcy estate. After customer sharing, Pepco recorded a pre-tax gain of $70.5 million related to the settlement of these claims.

Sale of Buzzard Point Property

     In August 2005, Pepco sold for $75 million in cash 384,051 square feet of excess non-utility land owned by Pepco located at Buzzard Point in the District of Columbia. The sale resulted in a pre-tax gain of $68.1 million which was recorded as a reduction of Operating Expenses in the Consolidated Statements of Earnings.

Financial Investment Liquidation

     In October 2005, PCI received $13.3 million in cash and recorded an after-tax gain of $8.9 million related to the liquidation of a financial investment that was written-off in 2001.

Capital Requirements

     Construction Expenditures

     Pepco Holdings' construction expenditures for the year ended December 31, 2006 totaled $474.6 million of which $447.2 million were related to the Power Delivery businesses and the remainder related to Conectiv Energy and Pepco Energy Services.

     For the five-year period 2007 through 2011, approximate construction expenditures are projected in the table below. The increase in the capital expenditure projections in 2006 compared to 2005 are primarily due to reliability (feeder conversions and cable and transformer replacements) and load-related projects within Power Delivery, and potential generation-related construction within the competitive businesses.

	For the Year
	2007	2008	2009	2010	2011	Total
Total	$630	$618	$535	$603	$758	$3,144
Power Delivery related	$581	$560	$489	$504	$573	$2,707

     For details on environmental costs included in the above table, see Item 1 "Business -- Environmental Matters." Pepco Holdings expects to fund these expenditures through internally generated cash from the Power Delivery businesses and from external financing.

     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. In 2006, PHI's Board of Directors declared quarterly dividends of 26 cents per share of common stock payable on March 31, 2006, June 30, 2006, September 29, 2006 and December 29, 2006.

     On January 25, 2007, the Board of Directors declared a dividend on common stock of 26 cents per share payable March 30, 2007, to shareholders of record March 12, 2007.

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     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) the prior rights of holders of existing and future 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 (iii) certain provisions of ACE's certificate of incorporation which provides that, if any preferred stock is outstanding, no dividends may be paid on the ACE common sto ck if, after payment, ACE's common stock capital plus surplus would be less than the involuntary liquidation value of the outstanding preferred stock. Pepco and DPL have no shares of preferred stock outstanding. Currently, the restriction in the ACE charter does not limit its ability to pay dividends.

     Pension Funding

     Pepco Holdings has a noncontributory retirement plan (the PHI Retirement Plan) that covers substantially all employees of Pepco, DPL and ACE and certain employees of other Pepco Holdings subsidiaries.

     As of the 2006 valuation, the PHI Retirement Plan satisfied the minimum funding requirements of the Employment Retirement Income Security Act of 1974 (ERISA) without requiring any additional funding. PHI's funding policy with regard to the PHI Retirement Plan is to maintain a funding level in excess of 100% of its accumulated benefit obligation (ABO). In 2006, no contribution was made to the PHI Retirement Plan. In 2005, PHI made a discretionary tax-deductible cash contribution in the amount of $60 million (all of which was funded by ACE) to the PHI Retirement Plan in accordance with its funding policy.

     In 2006, the ABO for the PHI Retirement Plan decreased from 2005, due to an increase in the discount rate used to value the ABO obligation, which more than offset the accrual of an additional year of service for participants. The PHI Retirement Plan assets achieved returns in 2006 above the 8.50% level assumed in the valuation. As a result of the combination of these factors, no contribution was made to the PHI Retirement Plan, because the funding level at year end 2006 was in excess of 100% of the ABO. In 2005, PHI contributed a total of $60 million (all of which was funded by ACE) to the PHI Retirement Plan. Assuming no changes to the current pension plan assumptions, PHI projects no funding will be required under ERISA in 2007; however, PHI may elect to make a discretionary tax-deductible contribution, if required to maintain its assets in excess of ABO for the PHI Retirement Plan. Recent legislative changes, in the form of the Pension Protection Act of 2006, impact t he funding requirements for pension plans beginning in 2008. The Pension Protection Act alters the manner in which liabilities and asset values are determined for the purpose of calculating required pension contributions. Based on preliminary actuarial projections and assuming no changes to current pension plan assumptions, PHI believes it is unlikely that there will be any required contribution in 2008.

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     Contractual Obligations And Commercial Commitments

     Summary information about Pepco Holdings' consolidated contractual obligations and commercial commitments at December 31, 2006, is as follows:

	Contractual Maturity
Obligation (a)	Total	Less than 1 Year	1-3   Years	3-5   Years	After     5 Years
	(Millions of dollars)
Variable rate demand bonds	$     154.2	$   154.2	$          -	$          -	$           -
Commercial paper	195.4	195.4	-	-	-
Long-term debt	5,093.1	855.1	405.8	601.8	3,230.4
PES project funding	25.7	2.4	4.5	3.7	15.1
Interest payments on debt	2,902.9	285.1	488.1	427.7	1,702.0
Capital leases	198.4	15.5	30.6	30.4	121.9
Operating leases	528.9	35.8	73.2	73.2	346.7
Non-derivative fuel and   purchase power contracts (b)	8,554.5	2,716.2	2,303.8	742.7	2,791.8
Total	$17,653.1	$4,259.7	$3,306.0	$1,879.5	$8,207.9

(a)	Estimates relating to the future funding of PHI's pension and other postretirement benefit plans are excluded from this table. For additional information, refer to Note (6) Pension and Other Postretirement Benefits -- "Cash Flows."
(b)	Excludes Mirant's obligations to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under a power purchase agreement with Panda-Brandywine, L.P. (the Panda PPA) that are part of the back-to-back agreement that was entered into with Mirant (See "Relationship with Mirant Corporation" for additional information) and excludes ACE's BGS load supply.

     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, 2006, 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		DPL		ACE		Other		Total
Energy marketing obligations of Conectiv Energy (1)	$	100.9	$	-	$	-	$	-	$	100.9
Energy procurement obligations ofPepco Energy Services (1)		206.7		-		-		-		206.7
Guaranteed lease residual values (2)		.5		3.3		3.2		-		7.0
Other (3)		2.9		-		-		1.9		4.8
Total	$	311.0	$	3.3	$	3.2	$	1.9	$	319.4

1.	Pepco Holdings has contractual commitments for performance and related payments of Conectiv Energy and Pepco Energy Services to counterparties related to routine energy sales and procurement obligations, including retail customer load obligations and requirements under BGS contracts entered into with ACE.
2.	Subsidiaries of Pepco Holdings have guaranteed residual values in excess of fair value related to certain equipment and fleet vehicles held through lease agreements. As of December 31, 2006, obligations under the guarantees were approximately $7.0 million. Assets leased under agreements subject to residual value guarantees are typically for periods ranging from 2 years to 10 years. Historically, payments under the guarantees have not been made by the guarantor as, under normal conditions, the contract runs to full term at which time the residual value is minimal. As such, Pepco Holdings believes the likelihood of payment being required under the guarantee is remote.
3.	Other guarantees consist of:
	·	Pepco Holdings has guaranteed a subsidiary building lease of $2.9 million. Pepco Holdings does not expect to fund the full amount of the exposure under the guarantee.
	·	PCI has guaranteed facility rental obligations related to contracts entered into by Starpower. As of December 31, 2006, the guarantees cover the remaining $1.9 million in rental obligations.
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     Energy Contract Net Asset Activity

     The following table provides detail on changes in the net asset or liability position of the Competitive Energy businesses (consisting of the activities of the Conectiv Energy and Pepco Energy Services segments) with respect to energy commodity contracts from one period to the next:

Roll-forward of Mark-to-Market Energy Contract Net Assets (Liabilities) For the Year Ended December 31, 2006 (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, 2005	$          -	$    59.9	$   59.9
Total change in unrealized fair value excluding     reclassification to realized at settlement of contracts	-	60.3	60.3
Reclassification to realized at settlement of contracts	-	(33.3)	(33.3)
Effective portion of changes in fair value - recorded     in Other Comprehensive Income	-	(151.3)	(151.3)
Ineffective portion of changes in fair value -     recorded in earnings	-	.1	.1
Total MTM Energy Contract Net     Liabilities at December 31, 2006	$          -	$   (64.3)	$ (64.3)
Detail of MTM Energy Contract Net Assets at December 31, 2006 (see above)			Total
Current Assets (other current assets)			$  80.0
Noncurrent Assets (other assets)			15.0
Total MTM Energy Assets			95.0
Current Liabilities (other current liabilities)			(128.6)
Noncurrent Liabilities (other liabilities)			(30.7)
Total MTM Energy Contract Liabilities			(159.3)
Total MTM Energy Contract Net Assets (Liabilities)			$ (64.3)

Notes:
(1)	PHI discontinued its proprietary trading activities in 2003.
(2)	Includes all SFAS No. 133 hedge activity and non-proprietary trading activities marked-to-market through earnings.

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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 businesses total mark-to-market energy contract net assets (liabilities). The table also provides the maturity, by year, of the Competitive Energy businesses mark-to-market energy contract net assets (liabilities), 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 businesses hold and sell. The fair values in each category presented below reflect forward prices and volatility factors as of December 31, 2006 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 (Liabilities) As of December 31, 2006 (Dollars are pre-tax and in millions)
	Fair Value of Contracts at December 31, 2006                           Maturities
Source of Fair Value	2007	2008	2009	2010 and  Beyond	Total Fair Value
Proprietary Trading
Actively Quoted (i.e., exchange-traded) prices	$       -	$       -	$      -	$      -	$       -
Prices provided by other external sources	-	-	-	-	-
Modeled	-	-	-	-	-
Total	$       -	$       -	$      -	$      -	$       -
Other Energy Commodity, net (1)
Actively Quoted (i.e., exchange-traded) prices	$(29.9)	$ (7.3)	$(2.2)	$   (.9)	$(40.3)
Prices provided by other external sources (2)	(23.5)	(9.3)	.7	(2.0)	(34.1)
Modeled (3)	4.8	3.4	1.5	.4	10.1
Total	$(48.6)	$(13.2)	$      -	$(2.5)	$(64.3)

Notes:
(1)	Includes all SFAS No. 133 hedge activity and non-proprietary trading activities marked-to-market through AOCI or on the Statements of earnings, as required.
(2)	Prices provided by other external sources reflect information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(3)	This modeled position represents SOS and associated supply that is receiving fair value accounting with the gains and losses recorded through current income. Pricing for the load portion of the transaction is modeled from broker quotes obtained for the closest trading hub, and adjusted for load following factors and historical congestion. Load volumes are adjusted for expected migration. Anticipated margin (Day 1 gain) on the transaction has been reserved in accordance with Emerging Issues Task Force (EITF) Issue No. 02-3.

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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 subsidiary may be required to provide cash collateral or letters of credit as security for its contractual obligations if the credit ratings of the subsidiary are downgraded. In the event of a downgrade, the amount required to be posted would depend on the amount of the underlying contractual obligation existing at the time of the downgrade. As of December 31, 2006, 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 an additional $389 million of aggregate cash collateral or letters of credit. PHI believes that it 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 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, 2006, Pepco Holdings' subsidiaries engaged in Competitive Energy activities and default supply activities provided cash collateral in the amount of approximately $99.0 million in connection with their competitive energy activities.

     Environmental Remediation Obligations

     PHI's accrued liabilities as of December 31, 2006 include approximately $21.3 million, of which $5.5 million is expected to be incurred in 2007, for potential environmental cleanup and other costs related to sites at which an operating subsidiary is a potentially responsible party (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 Item 1 "Business -- Environmental Matters." The principal environmental remediation obligations as of December 31, 2006, were:

·	$6.1 million, of which $930,000 is expected to be incurred in 2007, payable by DPL in accordance with a consent agreement reached with the Delaware Department of Natural Resources and Environmental Control (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 entry into a sale agreement in 2000 (which was subsequently terminated) for the B.L. England and Deepwater generating facilities (ACE transferred the Deepwater generating facility to Conectiv Energy in 2004) 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 have been continuing the investigation with oversight from New Jersey Department of Environmental Protection (NJDEP). Conectiv Energy anticipates that it will incur approximately $5.6 million in environmental remediation costs, of which $820,000 is
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	expected to be incurred in 2007, associated with the Deepwater generating facility. RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy Investments, LLC, the purchaser of the B.L. England generating facility, has entered into a remediation agreement with the NJDEP under which it will assume responsibility for remediation at B.L. England. In the event that RC Cape May fails to remediate groundwater or other resources at B.L. England, the responsibility for such remediation will revert to ACE.
·	DPL expects to incur costs of approximately $1.5 million (including approximately $260,000 in 2007) in connection with the Wilmington Coal Gas South site located in Wilmington, Delaware, to remediate residual material from the historical operation of a manufactured gas plant. Development pressure in the area of this site is expected to drive the scope and schedule of remediation during 2007.
·	Pepco expects to incur approximately $820,000 for long-term monitoring in connection with a pipeline oil release, of which it expects to incur $85,000 in 2007.

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 Item 1A. "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 fund temporarily 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 can be issued with maturities up to 270 days from the date of issue. The commercial paper programs of PHI, Pepco, DPL, and ACE are backed by a $1.2 billion credit facility.

     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 repay or refinance existing indebtedness.

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PUHCA 2005 Restrictions

     Under PUHCA 2005 and the Federal Power Act, FERC has jurisdiction (previously held by the SEC under PUHCA 1935) over the issuance of certain securities by Pepco, DPL and ACE. In accordance with regulations adopted by FERC, Pepco Holdings has notified FERC that it will continue until further notice to issue such securities under the authority granted in the financing order issued by the SEC under PUHCA 1935, which has an authorization period ending June 30, 2008 (the Financing Order). The Financing Order authorizes the issuance of equity, preferred securities and debt securities in an aggregate amount not to exceed $6 billion through an authorization period ending June 30, 2008, subject to a ceiling on the effective cost of these funds.

     In order to issue debt or equity securities pursuant to the Financing Order authorization, Pepco, ACE and DPL, respectively, must (a) maintain a ratio of common stock equity to total capitalization (consisting, for this purpose, of common stock, preferred stock, if any, long-term debt and short-term debt for this purpose) of at least 30 percent, and (b) have an "investment grade" rating by at least one nationally recognized rating agency for any rated securities issued. At December 31, 2006, the common equity ratios for purposes of the Financing Order for Pepco, DPL and ACE, respectively, were 46.2%, 44.6%, and 31.6%. If these conditions are not met, the affected utility could not issue the security under the Financing Order and may need to first obtain a new financing authorization from FERC.

     If FERC authorization pursuant to the Federal Power Act or FERC regulations is required to enable the utility subsidiaries to effect a financing, there is no certainty that such authorization could be obtained nor certainty as to the timing of FERC action.

Money Pool

     Under the Financing Order, Pepco Holdings operates a 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 its 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 borrowing needs of its participants, which may require Pepco Holdings to borrow funds for deposit from external sources.

REGULATORY AND OTHER MATTERS

Relationship with Mirant Corporation

     In 2000, Pepco sold substantially all of its electricity generating assets to Mirant (formerly Southern Energy, Inc.). In July 2003, Mirant 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). On December 9, 2005, the Bankruptcy Court approved the Plan of Reorganization (the Reorganization Plan) of Mirant, and the Mirant business emerged

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from bankruptcy on January 3, 2006, as a new corporation of the same name (for purposes of this section, together with its predecessors, Mirant).

     As part of the bankruptcy proceeding, Mirant had been seeking to reject certain ongoing contractual arrangements under the Asset Purchase and Sale Agreement entered into by Pepco and Mirant for the sale of the generating assets that are described below. The Reorganization Plan did not resolve the issues relating to Mirant's efforts to reject these obligations nor did it resolve certain Pepco damage claims against the Mirant bankruptcy estate.

     Power Purchase Agreement

     The Panda PPA obligates Pepco to purchase from Panda 230 megawatts of energy and capacity annually through 2021. At the time of the sale of Pepco's generating assets to Mirant, the purchase price of the energy and capacity under the Panda PPA was, and since that time has continued to be, substantially in excess of the 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 through 2021 to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the Panda PPA at a price equal to Pepco's purchase price from Panda (the PPA-Related Obligations).

     The SMECO Agreement

     Under the Asset Purchase and Sale Agreement, Pepco assigned to Mirant a Facility and Capacity Agreement entered into by Pepco with Southern Maryland Electric Cooperative, Inc. (SMECO), under which Pepco was obligated to purchase from SMECO the capacity of an 84-megawatt combustion turbine installed and owned by SMECO at a former Pepco generating facility at a cost of approximately $500,000 per month until 2015 (the SMECO Agreement). Pepco is responsible to SMECO for the performance of the SMECO Agreement if Mirant fails to perform its obligations thereunder.

     Settlement Agreements with Mirant

     On May 30, 2006, Pepco, PHI, and certain affiliated companies entered into a Settlement Agreement and Release (the Settlement Agreement) with Mirant, which, subject to court approval, settles all outstanding issues between the parties arising from or related to the Mirant bankruptcy. Under the terms of the Settlement Agreement:

·	Mirant will assume the Asset Purchase and Sale Agreement, except for the PPA-Related Obligations, which Mirant will be permitted to reject.
·	Pepco will receive an allowed claim under the Reorganization Plan in an amount that will result in a total aggregate distribution to Pepco, net of certain transaction expenses, of $520 million, consisting of (i) $450 million in damages resulting from the rejection of the PPA-Related Obligations and (ii) $70 million in settlement of other Pepco damage claims against the Mirant bankruptcy estate (the Pepco Distribution).
·	Except as described below, the $520 million Pepco Distribution will be effected by means of the issuance to Pepco of shares of Mirant common stock (consisting of an initial distribution of 13.5 million shares of Mirant common stock, followed thereafter by a number of shares of Mirant common stock to be determined), which Pepco will be obligated to resell promptly in one or more block sale transactions. If the net proceeds
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	that Pepco receives from the resale of the shares of Mirant common stock are less than $520 million, Pepco will receive a cash payment from Mirant equal to the difference, and if the net proceeds that Pepco receives from the resale of the shares of Mirant common stock are more than $520 million, Pepco will make a cash payment to Mirant equal to the difference.
·	If the closing price of shares of Mirant common stock is less than $16.00 per share for four business days in a twenty consecutive business day period, and Mirant has not made a distribution of shares of Mirant common stock to Pepco under the Settlement Agreement, Mirant has the one-time option to elect to assume, rather than reject, the PPA-Related Obligations. If Mirant elects to assume the PPA-Related Obligations, the Pepco Distribution will be reduced to $70 million.
·	All pending appeals, adversary actions or other contested matters between Pepco and Mirant will be dismissed with prejudice, and each will release the other from any and all claims relating to the Mirant bankruptcy.

     Separately, Mirant and SMECO have entered into a Settlement Agreement and Release (the SMECO Settlement Agreement). The SMECO Settlement Agreement provides that Mirant will assume, rather than reject, the SMECO Agreement. This assumption ensures that Pepco will not incur liability to SMECO as the guarantor of the SMECO Agreement due to the rejection of the SMECO Agreement, although Pepco will continue to guarantee to SMECO the future performance of Mirant under the SMECO Agreement.

     According to their terms, the Settlement Agreement and the SMECO Settlement Agreement will become effective when the Bankruptcy Court or the United States District Court for the Northern District of Texas (the District Court), as applicable, has entered a final order, not subject to appeal or rehearing, approving both the Settlement Agreement and the SMECO Settlement Agreement.

     On August 9, 2006, the Bankruptcy Court issued an order approving the Settlement Agreement and the SMECO Settlement Agreement. On August 18, 2006, certain holders of Mirant bankruptcy claims, who had objected to approval of the Settlement Agreement and the SMECO Settlement Agreement before the Bankruptcy Court, appealed the approval order to the District Court. On December 26, 2006, the District Court issued an order affirming the Bankruptcy Court's order approving the Settlement Agreement. On January 25, 2007, the parties that previously appealed the Bankruptcy Court's order filed a notice of appeal of the District Court's order with the United States Court of Appeals for the Fifth Circuit (the Fifth Circuit). On February 12, 2007, the Fifth Circuit issued a briefing schedule. The brief of the appealing creditors is due on March 26, 2007, while Mirant's and Pepco's briefs are due on April 30, 2007.

     In August 2006, Mirant made a cash payment to Pepco of $70 million, which became due in accordance with the terms of the Settlement Agreement as a result of the approval of the Settlement Agreement by the Bankruptcy Court. If the Bankruptcy Court order approving the Settlement Agreement becomes a final order after the exhaustion of all appeals, the payment will be taken into account as if it were proceeds from the resale by Pepco of shares of the Mirant common stock, as described above, and treated as a portion of the $520 million payment due Pepco. If the Bankruptcy Court approval of the Settlement Agreement is not upheld on appeal,

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Pepco must repay this cash payment to Mirant. Therefore, no income statement impact has been recognized in relation to the $70 million payment.

     Until the approval of the Settlement Agreement and the SMECO Settlement Agreement becomes final, Mirant is required to continue to perform all of its contractual obligations to Pepco and SMECO. Pepco intends to use the $450 million portion of the Pepco Distribution related to the rejection of the PPA-Related Obligations to pay for future capacity and energy purchases under the Panda PPA.

     In litigation prior to the entry into the Settlement Agreement, the District Court had entered orders denying Mirant's attempt to reject the PPA-Related Obligations and directing Mirant to resume making payments to Pepco pursuant to the PPA-Related Obligations, which Mirant had suspended. Mirant is making the payments as required by the District Court order. On July 19, 2006, the Fifth Circuit issued an opinion affirming the District Court's orders. On September 4, 2006, Mirant filed a petition for rehearing and motion to stay the appeals pending completion of the settlement between the parties. On September 12, 2006, the Fifth Circuit issued an Order denying Mirant's motion for stay. On September 21, 2006, the Fifth Circuit issued an Order summarily denying Mirant's petition for rehearing. The appeal period has expired and that order is now final and nonappealable.

Rate Proceedings

     PHI's regulated utility subsidiaries currently have four active distribution base rate cases underway. Pepco has filed electric distribution base rate cases in the District of Columbia and Maryland; DPL has filed a gas distribution base rate case in Delaware (which is the subject of a settlement agreement as discussed below) and an electric base rate case in Maryland. In each of these cases, the utility has proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers. The BSA will increase rates if revenues from distribution deliveries fall below the level approved by the applicable regulatory commission and will decrease rates if revenues from distribution deliveries are above the commission-approved level. The end result will be that the utility will collect its authorized revenues for distribution deliveries. As a consequence, a BSA "decouples" revenue from unit sales consumption and ties the growth in revenues to the growth in the num ber of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable utility distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers' delivery bills, and (iv) removes any disincentives for the regulated utilities to promote energy efficiency programs for their customers, because it breaks the link between overall sales volumes and delivery revenues. DPL has proposed a monthly BSA in the gas base rate case and, in each of the electric base rate cases, the companies have proposed a quarterly BSA.

     Delaware

     On August 31, 2006, DPL submitted its 2006 Gas Cost Rate (GCR) filing to the Delaware Public Service Commission (DPSC), which permits DPL to recover gas procurement costs through customer rates. The proposed decrease of approximately 9.6% is in anticipation of decreasing natural gas commodity costs. On October 3, 2006, the DPSC issued its initial order approving the proposed rates, which became effective November 1, 2006, subject to refund pending final DPSC approval after evidentiary hearings. Any amounts subject to refund would be deferred, resulting in no earnings impact.

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     On February 23, 2007, DPL submitted an additional filing to the DPSC that proposed a 4.3% decrease in the GCR effective April 1, 2007, in compliance with its gas service tariff and to ensure collections are more aligned with expenses. DPL expects DPSC approval of the rate decrease in late March 2007, subject to refund pending final DPSC approval after evidentiary hearings.

     On August 31, 2006, DPL submitted an application to the DPSC for an increase in gas distribution base rates, including a proposed BSA. The application requested an annual increase of approximately $15 million or an overall increase of 6.6%, including certain miscellaneous tariff fees, reflecting a proposed return on equity (ROE) of 11.00%. If the BSA is not approved, the proposed annual increase would be $15.5 million or an overall increase of 6.8%, reflecting an ROE of 11.25%. On October 17, 2006, the DPSC authorized DPL to place into effect beginning November 1, 2006, subject to refund, gas base rates designed to produce an annual interim increase in revenue of approximately $2.5 million. On February 16, 2007, all of the parties in this proceeding (DPL, DPSC staff and the Delaware Division of Public Advocate) filed a settlement agreement with the DPSC. The settlement provisions include a $9.0 million increase in distribution rates, including certain miscellaneous tarif f fees (of which $2.5 million was put into effect on November 1, 2006, as noted above), an ROE of 10.25%, and a change in depreciation rates that result in a $2.1 million reduction in pre-tax annual depreciation expense. Although the settlement agreement does not include a BSA, it provides for all of the parties to the case to participate in any generic statewide proceeding for the purpose of investigating BSA mechanisms for electric and gas distribution utilities. In a separate proceeding, DPL has requested that a docket be opened for this purpose. Under the settlement agreement, rates will become effective on April 1, 2007. A DPSC decision is expected by the end of March 2007.

     District of Columbia

     In February 2006, Pepco filed an update to the District of Columbia Generation Procurement Credit (GPC) for the periods February 8, 2002 through February 7, 2004 and February 8, 2004 through February 7, 2005. The GPC provides for sharing of the profit from SOS sales. The update to the GPC in the District of Columbia takes into account the $112.4 million in proceeds received by Pepco from the December 2005 sale of an allowed bankruptcy claim against Mirant arising from a settlement agreement entered into with Mirant relating to Mirant's obligation to supply energy and capacity to fulfill Pepco's SOS obligations in the District of Columbia. The filing also incorporates true-ups to previous disbursements in the GPC for the District of Columbia. In the filing, Pepco requested that $24.3 million be credited to District of Columbia customers during the twelve-month period beginning April 2006. On June 15, 2006, the District of Columbia Public Service Commission (DCPSC) granted conditional approval of the GPC update as filed, effective July 1, 2006. Final approval by the DCPSC is pending.

     On December 12, 2006, Pepco submitted an application to the DCPSC to increase electric distribution base rates, including a proposed BSA. The application requested an annual increase of approximately $46.2 million or an overall increase of 13.5%, reflecting a proposed ROE of 10.75%. If the BSA is not approved, the proposed annual increase would be $50.5 million or an overall increase of 14.8%, reflecting an ROE of 11.00%. The application also proposed a Pension/OPEB Expense Surcharge that will allow Pepco to reflect in its distribution rates the increases and decreases that occur in the level of its pension and other post-employment benefits expense. A DCPSC decision is expected in mid-September 2007.

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     Maryland

     On November 17, 2006, DPL and Pepco each submitted an application to the Maryland Public Service Commission (MPSC) to increase electric distribution base rates, including a proposed BSA. The applications requested an annual increase for DPL of approximately $18.4 million or an overall increase of 3.2%, including certain miscellaneous tariff fees, and an annual increase for Pepco of approximately $47.4 million or an overall increase of 10.9%, reflecting a proposed ROE for each of 11.00%. If the BSA is not approved, the proposed annual increase for DPL would be $20.3 million or an overall increase of 3.6%, and for Pepco would be $55.7 million or an overall increase of 12.9%, reflecting a proposed ROE for each of 11.25%. Each of the applications also proposed a Pension/OPEB Expense Surcharge that would allow the utility to reflect in its distribution rates the increases and decreases that occur in the level of its pension and other post-employment benefits expense. The appli cations requested that rates go into effect on December 17, 2006. In an order dated December 11, 2006, the MPSC suspended the proposed rates pending MPSC approval. MPSC decisions are expected in June 2007.

     Federal Energy Regulatory Commission

     On May 15, 2006, Pepco, ACE and DPL updated their FERC-approved formula transmission rates based on the FERC Form 1 data for 2005 for each of the utilities. These rates became effective on June 1, 2006, as follows: for Pepco, $12,009 per megawatt per year; for ACE, $14,155 per megawatt per year; and for DPL, $10,034 per megawatt per year. By operation of the formula rate process, the new rates incorporate true-ups from the 2005 formula rates that were effective June 1, 2005 and the new 2005 customer demand or peak load. Also, beginning in January 2007, the new rates will be applied to 2006 customer demand data, replacing the 2005 demand data that is currently used. This demand component is driven by the prior year peak loads experienced in each respective zone. Further, the rate changes will be positively impacted by changes to distribution rates for Pepco and DPL based on the merger settlements in Maryland and the District of Columbia. The net earnings impact expected from the network transmission rate changes is estimated to be a reduction of approximately $5 million year over year (2005 to 2006).

ACE Restructuring Deferral Proceeding

     Pursuant to orders issued by the NJBPU under the New Jersey Electric Discount and Energy Competition Act (EDECA), beginning August 1, 1999, ACE was obligated to provide BGS to retail electricity customers in its service territory who did not choose a competitive energy supplier. For the period August 1, 1999 through July 31, 2003, ACE's aggregate costs that it was allowed to recover from customers 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) related to ACE's Levelized Energy Adjustment Clause and ACE's Demand Side Management Programs. ACE established a regulatory asset in an amount equal to the balance of under-recovered costs.

     In August 2002, ACE filed a petition with the NJBPU for the recovery of approximately $176.4 million in actual and projected deferred costs relating to the provision of BGS and other restructuring related costs incurred by ACE over the four-year period August 1, 1999 through July 31, 2003, 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

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embedded in the rates on or after that date. The increase sought represented an overall 8.4% annual increase in electric rates.

     In July 2004, the NJBPU issued a final order in the restructuring deferral proceeding confirming a July 2003 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 then pending base rate case for further consideration approximately $25.4 million of the deferred balance (the base rate case ended in a settlement approved by the NJBPU in May 2005, the result of which is that any net rate impact from the deferral account recoveries and credits in future years will depend in part on whether rates associated with other deferred accounts considered in the case continue to generate over-collections relative to costs), 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. Although ACE believes the record does not justify the level of disallowance imposed by the NJBPU in the final order, the $44.6 million of disallowed incurred costs were reserved during the years 1999 through 2003 (primarily 2003) through charges to earnings, primarily in the operating expense line item "deferred electric service costs," with a corresponding reduction in the regulatory asset balance sheet account. In August 2004, ACE filed a notice of appeal with respect to the July 2004 final order with the Appellate Division of the Superior Court of New Jersey (the Appellate Division), which hears appeals of the decisions of New Jersey administrative agencies, including the NJBPU. Briefs in the appeal were also filed by the Division of the New Jersey Ratepayer Advocate and by Cogentrix Energy Inc., the co-owner of two cogeneration power plants with contracts to sell ACE approximately 397 megawatts of electricity, as cross-appellants between August 2005 and January 2006. The Appellate Division has not yet set the schedule for oral argument.

Divestiture Cases

     District of Columbia

     Final briefs on Pepco's District of Columbia divestiture proceeds sharing application were filed with the DCPSC in July 2002 following an evidentiary hearing in June 2002. That application was filed to implement a provision of Pepco's DCPSC-approved divestiture settlement that provided for a sharing of any net proceeds from the sale of Pepco's generation-related assets. One of the principal issues in the case is whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code (IRC) and its implementing regulations. As of December 31, 2006, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6.5 million and $5.8 million, respectively.

     Pepco believes that a sharing of EDIT and ADITC would violate the IRS normalization rules. Under these rules, Pepco could not transfer the EDIT and the ADITC benefit to customers more quickly than on a straight line basis over the book life of the related assets. Since the assets are no longer owned there is no book life over which the EDIT and ADITC can be returned. If Pepco were required to share EDIT and ADITC and, as a result, the normalization rules were violated, Pepco would be unable to use accelerated depreciation on District of Columbia allocated or assigned property. In addition to sharing with customers the generation-related

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EDIT and ADITC balances, Pepco would have to pay to the IRS an amount equal to Pepco's District of Columbia jurisdictional generation-related ADITC balance ($5.8 million as of December 31, 2006), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($4.7 million as of December 31, 2006) in each case as those balances exist as of the later of the date a DCPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the DCPSC order becomes operative.

     In March 2003, the IRS issued a notice of proposed rulemaking (NOPR), which would allow for the sharing of EDIT and ADITC related to divested assets with utility customers on a prospective basis and at the election of the taxpayer on a retroactive basis. In December 2005 a revised NOPR was issued which, among other things, withdrew the March 2003 NOPR and eliminated the taxpayer's ability to elect to apply the regulation retroactively. Comments on the revised NOPR were filed in March 2006, and a public hearing was held in April 2006. Pepco filed a letter with the DCPSC in January 2006, in which it has reiterated that the DCPSC should continue to defer any decision on the ADITC and EDIT issues until the IRS issues final regulations or states that its regulations project related to this issue will be terminated without the issuance of any regulations. Other issues in the divestiture proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.

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

     Maryland

    Pepco filed its divestiture proceeds plan application with the MPSC in April 2001. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that has been raised in the District of Columbia case. See the discussion above under "Divestiture Cases -- District of Columbia." As of December 31, 2006, the Maryland allocated portions of EDIT and ADITC associated with the divested generating 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 with respect to the application 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 (discussed abo ve) 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 ($9.1 million as of December 31, 2006), and the Maryland-allocated portion of generation-related ADITC. Furthermore, Pepco would have to pay to the IRS an amount equal to Pepco's Maryland jurisdictional generation-related

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ADITC balance ($10.4 million as of December 31, 2006), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($8.4 million as of December 31, 2006), in each case as those balances exist 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. The Hearing Examiner decided all other issues in favor of Pepco, except for the determination that only one-half of the severance payments that Pepco included in its calculation of corporate reorganization costs should be deducted from the sales proceeds before sharing of the net gain between Pepco and customers. Pepco filed a letter with the MPSC in January 2006, in which it has reiterated that the MPSC should continue to defer any decision on the ADITC and EDIT issues until the IRS issues final regulations or states that its regulations project related to this issue will be terminated without the issuance of any reg ulations.

     In December 2003, Pepco appealed the Hearing Examiner's decision to the MPSC as it relates to the treatment of EDIT and ADITC and corporate reorganization costs. The MPSC has not issued any ruling on the appeal and Pepco does not believe that it will do so until action is taken by the IRS as described above. 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 in addition to the additional gain-sharing payments relating to the disallowed severance payments, which Pepco is not contesting. 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 mate rial adverse impact on its financial position or cash flows.

     New Jersey

     In connection with the divestiture by ACE of its nuclear generating assets, the NJBPU in July 2000 preliminarily determined that the amount of stranded costs associated with the divested assets that ACE could recover from ratepayers should be reduced by approximately $94.5 million, representing the amount of the accumulated deferred federal income taxes (ADFIT) associated with the divested nuclear assets. However, due to uncertainty under federal tax law regarding whether the sharing of federal income tax benefits associated with the divested assets, including ADFIT, with ACE's customers would violate the normalization rules, ACE submitted a request to the IRS for a Private Letter Ruling (PLR) to clarify the applicable law. The NJBPU has delayed its final determination of the amount of recoverable stranded costs until after the receipt of the PLR.

     On May 25, 2006, the IRS issued a PLR in which it stated that returning to ratepayers any of the unamortized ADFIT attributable to accelerated depreciation on the divested assets after the sale of the assets by means of a reduction of the amount of recoverable stranded costs would violate the normalization rules.

     On June 9, 2006, ACE submitted a letter to the NJBPU to request that the NJBPU conduct proceedings to finalize the determination of the stranded costs associated with the sale of ACE's nuclear assets in accordance with the PLR. ACE's request remains pending.

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Default Electricity Supply Proceedings

     Delaware

     Effective May 1, 2006, SOS replaced fixed-rate POLR service for customers who do not choose an alternative electricity supplier. In October 2005, the DPSC approved DPL as the SOS provider to its Delaware delivery customers. DPL obtains the electricity to fulfill its SOS supply obligation under contracts entered pursuant to a competitive bid procedure approved by the DPSC. The bids received for the May 1, 2006, through May 31, 2007, period have had the effect of increasing rates significantly for all customer classes, including an average residential customer increase of 59%, as compared to the fixed rates previously in effect.

     To address this increase in rates, Delaware in April 2006 enacted legislation that provides for a deferral of the financial impact on customers of the increases through a three-step phase-in of the rate increases, with 15% of the increase taking effect on May 1, 2006, 25% of the increase taking effect on January 1, 2007, and any remaining balance taking effect on June 1, 2007, subject to the right of customers to elect not to participate in the deferral program. Customers who do not "opt-out" of the rate deferral program are required to pay the amounts deferred, without any interest charge, over a 17-month period beginning January 1, 2008. As of December 31, 2006, approximately 53% of the eligible Delaware customers have opted not to participate in the deferral of the SOS rates offered by DPL. With approximately 47% of the eligible customers participating in the phase-in program, DPL anticipates a maximum deferral balance of $51.4 million.

     Maryland

     Pursuant to orders issued by the MPSC in November 2006, Pepco and DPL each is the SOS provider to its delivery customers who do not choose an alternative electricity supplier. Each company purchases the power supply required to satisfy its SOS obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved and supervised by the MPSC. In March 2006, Pepco and DPL each announced the results of competitive bids to supply electricity to its Maryland SOS customers for one year beginning June 1, 2006. Due to significant increases in the cost of fuels used to generate electricity, the auction results had the effect of increasing the average monthly electric bill by about 38.5% and 35% for Pepco's and DPL's Maryland residential customers, respectively.

     On April 21, 2006, the MPSC approved a settlement agreement among Pepco, DPL, the staff of the MPSC and the Office of Peoples Counsel of Maryland, which provides for a rate mitigation plan for the residential customers of each company. Under the plan, the full increase for each company's residential customers who affirmatively elect to participate are being phased-in in increments of 15% on June 1, 2006, 15.7% on March 1, 2007 and the remainder on June 1, 2007. Customers electing to participate in the rate deferral plan will be required to pay the deferred amounts over an 18-month period beginning June 1, 2007. Both Pepco and DPL will accrue the interest cost to fund the deferral program. The interest cost will be absorbed by Pepco and DPL during the period that the deferred balance is accumulated and collected from customers, to the extent of and offset against the margins that the companies otherwise would earn for providing SOS to residential customers. As of Dec ember 31, 2006, approximately 2% of Pepco's residential customers and approximately 1% of DPL's residential customers had elected to participate in the phase-in program.

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     On June 23, 2006, Maryland enacted legislation that extended the period for customers to elect to participate in the phase-in of higher rates and revised the obligation to provide SOS to residential and small commercial customers until further action of the General Assembly. The legislation also provides for a customer refund reflecting the difference between the interest expense on an initially projected deferred balance at a 25% customer participation level and the interest expense on a deferred balance based on actual participation levels referred to above. The total amount of the refund is approximately $1.1 million for Pepco customers and approximately $.3 million for DPL customers. At Pepco's 2% level of participation, Pepco estimates that the deferral balance, net of taxes, will be approximately $1.4 million. At DPL's 1% level of participation, DPL estimates that the deferral balance, net of taxes, will be approximately $.2 million. In July 200 6, the MPSC approved revised tariff riders filed in June 2006 by Pepco and DPL to implement the legislation.

     Virginia

     On March 10, 2006, DPL filed for a rate increase with the Virginia State Corporation Commission (VSCC) for its Virginia Default Service customers to take effect on June 1, 2006, which was intended to allow DPL to recover its higher cost for energy established by the competitive bid procedure. On June 19, 2006, the VSCC issued an order that granted a rate increase for DPL of $11.5 million ($8.5 million less than requested by DPL in its March 2006 filing), to go into effect July 1, 2006. In determining the amount of the approved increase, the VSCC applied the proxy rate calculation to DPL's fuel factor, rather than allowing full recovery of the costs DPL incurred in procuring the supply necessary for its Default Service obligation. The estimated after-tax earnings and cash flow impacts of the decision are reductions of approximately $3.6 million in 2006 (including the loss of revenue in June 2006 associated with the Default Service rate increase being deferred from June 1 un til July 1) and $2.0 million in 2007. The order also mandated that DPL file an application by March 1, 2007 (which has been delayed until April 2, 2007 by subsequent VSCC order) for Default Service rates to become effective June 1, 2007, which should include a calculation of the fuel factor that is consistent with the procedures set forth in the order.

     In February 2007, the Virginia General Assembly passed amendments to the Virginia Electric Utility Restructuring Act (the Virginia Restructuring Act) that modified the method by which investor-owned electric utilities in Virginia will be regulated by the VSCC. These amendments to the Virginia Restructuring Act, subject to further amendment or veto by the Virginia governor and subsequent action by the General Assembly, will be effective on July 1, 2007. The amendments provide that, as of December 31, 2008, the following will come to an end: (i) capped rates (the previous expiration date was December 31, 2010); (ii) DPL's Default Service obligation (previously, DPL was obligated to continue to offer Default Service until relieved of that obligation by the VSCC); and (iii) customer choice, except that customers with loads of 5 megawatts or greater will continue to be able to buy from competitive suppliers, as will smaller non-residential customers tha t aggregate their loads to reach the 5 megawatt threshold and obtain VSCC approval. Additionally, if an ex-customer of Default Service wants to return to DPL as its energy supplier, it must give 5 years notice or obtain approval of the VSCC that the return is in the public interest. In this event, the ex-customer must take DPL's service at market based rates. DPL also believes that the amendments to the Virginia Restructuring Act will terminate, as of December 31, 2008, the ratemaking provisions within the memorandum of agreement entered into by DPL, the staff of the VSCC and the Virginia Attorney General's office in the docket approving DPL's generating asset divestiture in 2000 (the

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MOA), including the application of the proxy rate calculation to DPL's fuel factor as discussed above; however, the VSCC's interpretation of these provisions is not known. It should be noted that in DPL's view, in the absence these amendments, the MOA and all of its provisions (including the proxy rate calculation) expire on July 1, 2007; the VSCC staff and the Virginia Attorney General disagree with DPL's position. Assuming the ratemaking provisions of the MOA end on December 31, 2008 pursuant to the amended Virginia Restructuring Act, the amendments provide that DPL shall file a rate case in 2009 and every 2 years thereafter. The ROE to be allowed by the VSCC will be set within a range, the lower of which is essentially the average of vertically integrated investor-owned electric utilities in the southeast with an upper point that is 300 basis points above that average. The VSCC has authority to set rates higher or lower to allow DPL to maintain the opportunity to earn the determined ROE and to cred it back to customers, in whole or in part, earnings that were 50 basis points or more in excess of the determined ROE. The amended Virginia Restructuring Act includes various incentive ROEs for the construction of new generation and would allow the VSCC to penalize or reward DPL for efficient operations or, if DPL were to add new generation, for generating unit performance. There are also enhanced ratemaking features if DPL pursues conservation, demand management and energy efficiency programs or pursues renewable energy portfolios.

ACE Sale of Generating Assets

     On September 1, 2006, ACE completed the sale of its interests in the Keystone and Conemaugh generating facilities to Duquesne Light Holdings Inc. for approximately $177.0 million, which was subsequently decreased by $1.6 million based on a post-closing 60-day true-up for applicable items not known at the time of the closing. Approximately $81.3 million of the net gain from the sale has been used to offset the remaining regulatory asset balance, which ACE has been recovering in rates, and approximately $49.8 million of the net gain is being returned to ratepayers over a 33-month period as a credit on their bills, which began with the October 2006 billing month. The balance to be repaid to customers is $48.4 million as of December 31, 2006.

     On February 8, 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May for a price of $9.0 million, after adjustment for, among other things, variances in the value of fuel and material inventories at the time of closing, plant operating capacity, the value of certain benefits for transferred employees and the actual closing date. The purchase price will be further adjusted based on a post-closing 60-day true-up for applicable items not known at the time of the closing. In addition, RC Cape May and ACE have agreed to arbitration concerning whether RC Cape May must pay to ACE, as part of the purchase price, an additional $3.1 million remaining in dispute. RC Cape May also assumed certain liabilities associated with the B.L. England generating station, including substantially all environmental liabilities. This transaction is further described below under the heading "Environmental Litigation."

     The sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized. ACE anticipates that approximately $9 to $10 million of additional regulatory assets related to B.L. England may, subject to NJBPU approval, be eligible for recovery as stranded costs. The emission allowance credits associated with B. L. England will be monetized for the benefit of ACE's ratepayers pursuant to the NJBPU order approving the sale. Net proceeds from the sale of the plant and monetization of the emission allowance credits, which will be determined after the sale upon resolution of certain adjustments, will be credited to ACE's ratepayers in accordance with the requirements of EDECA and NJBPU orders.

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General Litigation

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

     Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed. As a result of two motions to dismiss, numerous hearings and meetings and one motion for summary judgment, Pepco has had approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of January 31, 2007, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland; of which 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. Under the terms of the Settlement Agreement, Mirant has agreed to assume this contractual obligation. For a description of the Settlement Agreement, see the discussion of the relationship with Mirant above.

     While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) exceeds $360 million, PHI and Pepco believe 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, neither PHI nor Pepco believes these suits will have a material adverse effect on its financial position, results of operations or cash flows. However, if an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco's and PHI's financial position, results of operations or cash flows.

Cash Balance Plan Litigation

     In 1999, Conectiv established a cash balance retirement plan to replace defined benefit retirement plans then maintained by ACE and DPL. Following the acquisition by Pepco of Conectiv, this plan became the Conectiv Cash Balance Sub-Plan within the PHI Retirement Plan. On September 26, 2005, three management employees of PHI Service Company filed suit in the United States District Court for the District of Delaware (the Delaware District Court) against the PHI Retirement Plan, PHI and Conectiv (the PHI Parties), alleging violations of ERISA, on behalf of a class of management employees who did not have enough age and service when the Cash Balance Sub-Plan was implemented in 1999 to assure that their accrued benefits would be calculated pursuant to the terms of the predecessor plans sponsored by ACE and DPL. A fourth plaintiff was added to the case to represent DPL-heritage "grandfathered" employees who will not be eligible for early retirement at the end of the grandfathere d period.

     The plaintiffs have challenged the design of the Cash Balance Sub-Plan and are seeking a declaratory judgment that the Cash Balance Sub-Plan is invalid and that the accrued benefits of each member of the class should be calculated pursuant to the terms of the predecessor plans. Specifically, the complaint alleges that the use of a variable rate to compute the plaintiffs'

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accrued benefit under the Cash Balance Sub-Plan results in reductions in the accrued benefits that violate ERISA. The complaint also alleges that the benefit accrual rates and the minimal accrual requirements of the Cash Balance Sub-Plan violate ERISA as did the notice that was given to plan participants upon implementation of the Cash Balance Sub-Plan.

     The PHI Parties filed a motion to dismiss the suit, which was denied by the court on July 11, 2006. The Delaware District Court stayed one count of the complaint regarding alleged age discrimination pending a decision in another case before the United States Court of Appeals for the Third Circuit (the Third Circuit). On January 30, 2007, the Third Circuit issued a ruling in the other case that PHI's counsel believes should result in the favorable disposition of all of the claims (other than the claim of inadequate notice) against the PHI Parties in the Delaware District Court. The PHI Parties filed pleadings apprising the Delaware District Court of the Third Circuit's decision on February 16, 2007, at the same time they filed their opposition to plaintiffs' motion.

     While PHI believes it has an increasingly strong legal position in the case and that it is therefore unlikely that the plaintiffs will prevail, PHI estimates that, if the plaintiffs were to prevail, the ABO and projected benefit obligation (PBO), calculated in accordance with SFAS No. 87, each would increase by approximately $12 million, assuming no change in benefits for persons who have already retired or whose employment has been terminated and using actuarial valuation data as of the time the suit was filed. The ABO represents the present value that participants have earned as of the date of calculation. This means that only service already worked and compensation already earned and paid is considered. The PBO is similar to the ABO, except that the PBO includes recognition of the effect that estimated future pay increases would have on the pension plan obligation.

Environmental Litigation

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

     In July 2004, DPL entered into an administrative consent order (ACO) 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 a Cambridge, Maryland site on DPL-owned property and to investigate the extent of MGP contamination on adjacent property. The MDE has approved the RI and DPL submitted a final FS to MDE on February 15, 2007. The costs of cleanup (as determined by the RI/FS and subsequent negotiations with MDE) are anticipated to be approximately $2.7 million. The remedial action will include dredging activities within Cambridge Creek, which are expected to take place as

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early as October 2007, and soil excavation on DPL's and adjacent property as early as January 2008.

     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 the U.S. Environmental Protection Agency (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 1994, an RI/FS including a number of possible remedies was submitted to the EPA. In 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 1998, the EPA issued a unilateral administrative order to Pepco and 12 other PRPs directing them to conduct the design and actions called for in its decision. In May 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. In October 2003, the bankruptcy court confirmed a reorganization plan that incorporates the terms of a settlement among the two debtor owner/operator entities, the United States and a group of utility PRPs including Pepco (the Utility PRPs). Under the bankruptcy settlement, the reorganized entity/site owner will pay a total of $13.25 million to remediate the site (the Bankruptcy Settlement).

     In March 2006, the United States District Court for the Eastern District of Pennsylvania approved global consent decrees for the Metal Bank/Cottman Avenue site, entered into on August 23, 2005, involving the Utility PRPs, the U.S. Department of Justice, EPA, The City of Philadelphia and two owner/operators of the site. Under the terms of the settlement, the two owner/operators will make payments totaling $5.55 million to the U.S. Department of Justice and totaling $4.05 million to the Utility PRPs. The Utility PRPs will perform the remedy at the site and will be able to draw on the $13.25 million from the Bankruptcy Settlement to accomplish the remediation (the Bankruptcy Funds). The Utility PRPs will contribute funds to the extent remediation costs exceed the Bankruptcy Funds available. The Utility PRPs also will be liable for EPA costs associated with overseeing the monitoring and operation of the site remedy after the remedy construction is certified to be complete and also the cost of performing the "5 year" review of site conditions required by the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Any Bankruptcy Funds not spent on the remedy may be used to cover the Utility PRPs' liabilities for future costs. No parties are released from potential liability for damages to natural resources.

     As of December 31, 2006, Pepco had accrued $1.7 million to meet its liability for a remedy at the Metal Bank/Cottman Avenue site. While final costs to Pepco of the settlement have not been determined, Pepco believes that its liability at this site will not have a material adverse effect on its financial position, results of operations or cash flows.

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

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     In November 1991, the 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 ACO 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. Positive results of groundwater monitoring events have resulted in a reduced level of groundwater monitoring. In August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site. Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years and to continue groundwater monitoring.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 anticipates that its share of additional cost associated with this site will be approximately $555,000 to $600,000. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial position, results of operations or cash flows.

     On January 24, 2006, PHI, Conectiv and ACE entered into an ACO with NJDEP and the Attorney General of New Jersey resolving (i) New Jersey's claim for alleged violations of the federal Clean Air Act (CAA) and (ii) the NJDEP's concerns regarding ACE's compliance with New Source Review requirements of the CAA and Air Pollution Control Act requirements with respect to the B.L. England generating facility and various other environmental issues relating to ACE and Conectiv Energy facilities in New Jersey. See Item 1 "Business -- Environmental Matters -- Air Quality Regulation."

Federal Tax Treatment of Cross-Border Leases

     PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which, as of December 31, 2006, had a book value of approximately $1.3 billion, and from which PHI currently derives approximately $57 million per year in tax benefits in the form of interest and depreciation deductions.

     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 entering into certain sale-leaseback transactions with tax-indifferent parties (i.e., municipalities, tax-exempt and governmental entities), including those entered into on or prior to March 12, 2004 (the Notice). All of PCI's cross-border energy leases are with tax indifferent parties and were entered into prior to 2004. In addition, on June 29, 2005 the IRS published a Coordinated Issue Paper concerning the resolution of audit issues related to such transactions. PCI's cross-border energy leases are similar to those sale-leaseback transactions described in the Notice and the Coordinated Issue Paper.

     PCI's leases have been under examination by the IRS as part of the normal PHI tax audit. On June 9, 2006, the IRS issued its final revenue agent's report (RAR) for its audit of PHI's 2001 and 2002 income tax returns. In the RAR, the IRS disallowed the tax benefits claimed by PHI with respect to these leases for those years. The tax benefits claimed by PHI with respect to these leases from 2001 through December 31, 2006 were approximately $287 million. PHI has filed a protest against the IRS adjustments and the unresolved audit has been forwarded to the Appeals Office. 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

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additional taxes, which could have a material adverse effect on PHI's financial condition, results of operations, and cash flows. PHI believes that its tax position related to these transactions was appropriate based on applicable statutes, regulations and case law, and intends to contest the adjustments proposed by the IRS; however, there is no assurance that PHI's position will prevail.

     On July 13, 2006, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) on Financial Accounting Standards (FAS) 13-2, which amends SFAS No. 13 effective for fiscal years beginning after December 15, 2006. This amendment requires a lease to be repriced and the book value adjusted when there is a change or probable change in the timing of tax benefits of the lease regardless of whether the change results in a deferral or permanent loss of tax benefits. Accordingly, a material change in the timing of cash flows under PHI's cross-border leases as the result of a settlement with the IRS would require an adjustment to the book value of the leases and a charge to earnings equal to the repricing impact of the disallowed deductions which could result in a material adverse effect on PHI's financial condition, results of operations, and cash flows. PHI believes its tax position was appropriate and at this time does not believe there is a probable change in the timing of its tax benefits that would require repricing the leases and a charge to earnings.

     On February 1, 2007 the U.S. Senate passed the Small Business and Work Opportunity Act of 2007. Included in this legislation is a provision which would apply passive loss limitation rules to leases with foreign tax indifferent parties effective for taxable years beginning after December 31, 2006, even if the leases were entered into on or prior to March 12, 2004. On February 16, 2007, the U.S. House of Representatives passed the Small Business Relief Act of 2007. This bill does not include any provision that would modify the current treatment of leases with tax indifferent parties. Enactment into law of a bill that is similar to that passed by the U.S. Senate in its current form could result in a material delay of the income tax benefits that PCI would receive in connection with its cross-border energy leases. Furthermore, under FSP FAS 13-2, PHI would be required to adjust the book values of its leases and record a charge to earnings equal to the repricing impact of th e disallowed deductions which could result in a material adverse effect on PHI's financial condition, results of operations and cash flows. The U.S. House of Representatives and the U.S. Senate are expected to hold a conference in the near future to reconcile the differences in the two bills to determine the final legislation.

IRS Mixed Service Cost Issue

     During 2001, Pepco, DPL, and ACE changed their methods of accounting with respect to capitalizable construction costs for income tax purposes. The change allowed the companies to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through December 31, 2005, these accelerated deductions generated incremental tax cash flow benefits of approximately $205 million (consisting of $94 million for Pepco, $62 million for DPL, and $49 million for ACE) for the companies, primarily attributable to their 2001 tax returns.

     On August 2, 2005, the Treasury Department released regulations that, if adopted in their current form, would require Pepco, DPL, and ACE to change their method of accounting with respect to capitalizable construction costs for income tax purposes for tax periods beginning in 2005. Based on those regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believes will be acceptable to the IRS.

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     On the same day that the new regulations were released, the IRS issued Revenue Ruling 2005-53, which is intended to limit the ability of certain taxpayers to utilize the method of accounting for income tax purposes they utilized on their tax returns for 2004 and prior years with respect to capitalizable construction costs. In line with this Revenue Ruling, the IRS RAR for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that Pepco, DPL and ACE had claimed on those returns by requiring the companies to capitalize and depreciate certain expenses rather than treat such expenses as current deductions. PHI's protest of the IRS adjustments is among the unresolved audit matters relating to the 2001 and 2002 audits pending before the Appeals Office.

     In February 2006, PHI paid approximately $121 million of taxes to cover the amount of taxes that management estimated to be payable based on the method of tax accounting that PHI, pursuant to the proposed regulations, has adopted on its 2005 tax return. However, if the IRS is successful in requiring Pepco, DPL and ACE to capitalize and depreciate construction costs that result in a tax and interest assessment greater than management's estimate of $121 million, PHI will be required to pay additional taxes and interest only to the extent these adjustments exceed the $121 million payment made in February 2006.

IRS Examination of Like-Kind Exchange Transaction

     In 2001, Conectiv and certain of its subsidiaries (the Conectiv Group) were divesting nonstrategic electric generating facilities and replacing these facilities with mid-merit electric generating capacity. As part of this strategy, the Conectiv Group exchanged its interests in two older coal-fired plants for the more efficient gas-fired Hay Road II generating facility, which was owned by an unaffiliated third party. For tax purposes, Conectiv treated the transaction as a "like-kind exchange" under IRC Section 1031. As a result, approximately $88 million of taxable gain was deferred for federal income tax purposes.

     The transaction was examined by the IRS as part of the normal Conectiv tax audit. In May 2006, the IRS issued its RAR for the audit of Conectiv's 2000, 2001 and 2002 income tax returns. In the RAR, the IRS exam team disallowed the qualification of the exchange under IRC Section 1031. In July 2006, Conectiv filed a protest of this disallowance to the IRS Office of Appeals.

     PHI believes that its tax position related to this transaction is proper based on applicable statutes, regulations and case law and intends to vigorously contest the disallowance. However, there is no absolute assurance that Conectiv's position will prevail. If the IRS prevails, Conectiv would be subject to additional income taxes, interest and possible penalties. However, a portion of the denied benefit would be offset by additional tax depreciation.

     As of December 31, 2006, if the IRS fully prevails, the potential cash impact on PHI would be current income tax and interest payments of approximately $29 million and the earnings impact would be approximately $7 million in after-tax interest.

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

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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.

     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 (see "Relationship with Mirant Corporation"), the calculation of future cash flows and fair value amounts for use in goodwill and asset impairment evaluations, fair value calculations (based on estimated market pricing) associated with derivative instruments, pension and other postretirement benefits assumptions, unbilled revenue calculations, and the 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. Pepco Holdings records an estimated liability for these proceedings and claims based upon the probable and reasonably estimable criteria contained in SFAS No. 5, "Accounting for Contingencies." Although Pepco Holdings believes that its estimates and assu mptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

     Goodwill Impairment Evaluation

     Pepco Holdings believes that the estimates involved in its goodwill impairment evaluation process represent "Critical Accounting Estimates" because (i) they 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 and 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. The goodwill 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 expenditu re requirements and other factors, changes in which could materially impact the results of impairment testing. Pepco Holdings tested its goodwill for

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impairment as of July 1, 2006. This testing concluded that Pepco Holdings' goodwill balance was not impaired. A hypothetical decrease in the 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 (i) they 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 may 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 not to 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 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 val ue of goodwill, which is discussed above.

     For a discussion of PHI's impairment losses during 2006, refer to the "Impairment Losses" section in the accompanying Consolidated Results of Operations discussion.

     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/or 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. See Note (2), "Summary of Significant Accounting Policies - Accounting for Derivatives" to the consolidated financial statements of PHI included in Item 8 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

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custom and complex instruments, an internal model is used to interpolate broker quality price information. The same valuation methods are used to determine the value of non-derivative, commodity exposure for risk management purposes.

     Pension and Other Postretirement Benefit Plans

     Pepco Holdings believes that the estimates involved in reporting the costs of providing pension and other postretirement 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 postretirement benefit liability on the balance sheet, and the reported annual net periodic pension and other postretirement 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 benefit obligations could result in a $ 5 million impact on its consolidated balance sheets and statements of earnings. 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 statements of earnings and a .25% change in the assumed healthcare cost trend rate could result in a $.5 million impact on its consolidated balance sheets and statements of earnings. Pepco Holdings' management consults with its actuaries and investment consultants when selecting its plan assumptions.

     Pepco Holdings follows the guidance of SFAS No. 87, "Employers' Accounting for Pensions," SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," and SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R)" (SFAS No. 158), 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 postretirement obligations is generally recognized over the working lives of the employees who benefit under the plans rather than immediately recognized in the statements of earnings. Plan assets are stated at their market value as of the measurement date, which is December 31.

     Regulation of Power Delivery Operations

     The requirements of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," 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.

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     Unbilled Revenue

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

New Accounting Standards

     FSP FTB 85-4-1, "Accounting for Life Settlement Contracts by Third-Party Investors"

     In March 2006, the FASB issued FSP FASB Technical Bulletin (FTB) 85-4-1, "Accounting for Life Settlement Contracts by Third-Party Investors" (FSP FTB 85-4-1). This FSP provides initial and subsequent measurement guidance and financial statement presentation and disclosure guidance for investments by third-party investors in life settlement contracts. FSP FTB 85-4-1 also amends certain provisions of FASB Technical Bulletin No. 85-4, "Accounting for Purchases of Life Insurance," and SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The guidance in FSP FTB 85-4-1 applies prospectively for all new life settlement contracts and is effective for fiscal years beginning after June 15, 2006 (the year ending December 31, 2007 for Pepco Holdings). Pepco Holdings has evaluated the impact of FSP FTB 85-4-1 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, or cash flows.

     EITF 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

     In September 2005, the FASB ratified EITF Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty" (EITF 04-13), which addresses circumstances under which two or more exchange transactions involving inventory with the same counterparty should be viewed as a single exchange transaction for the purposes of evaluating the effect of Accounting Principles Board (APB) Opinion 29, "Accounting for Nonmonetary Transactions." EITF 04-13 is effective for new arrangements entered into, or modifications or renewals of existing arrangements, beginning in the first interim or annual reporting period beginning after March 15, 2006.

     Pepco Holdings implemented EITF 04-13 on April 1, 2006. The implementation did not have a material impact on Pepco Holdings' overall financial condition, results of operations, or cash flows for the second quarter of 2006.

     SFAS No. 155, "Accounting for Certain Hybrid Financial Instruments - an amendment of FASB Statements No. 133 and 140"

     In February 2006, the FASB issued SFAS No. 155, "Accounting for Certain Hybrid Financial Instruments - an amendment of FASB Statements No. 133 and 140" (SFAS No. 155). SFAS No. 155 amends FASB Statements No. 133, "Accounting for Derivative Instruments and Hedging Activities," and No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." SFAS No. 155 resolves issues addressed in Statement 133

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Implementation Issue No. D1, "Application of Statement 133 to Beneficial Interests in Securitized Financial Assets." SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity's first fiscal year that begins after September 15, 2006 (year ending December 31, 2007 for Pepco Holdings). Pepco Holdings has evaluated the impact of SFAS No. 155 and does not anticipate that its implementation will have a material impact on its overall financial condition, results of operations, or cash flows.

     SFAS No. 156, "Accounting for Servicing of Financial Assets, an amendment of FASB Statement No. 140"

     In March 2006, the FASB issued SFAS No. 156, "Accounting for Servicing of Financial Assets" (SFAS No. 156), an amendment of SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," with respect to the accounting for separately recognized servicing assets and servicing liabilities. SFAS No. 156 requires an entity to recognize a servicing asset or servicing liability upon undertaking an obligation to service a financial asset via certain servicing contracts, and for all separately recognized servicing assets and servicing liabilities to be initially measured at fair value, if practicable. Subsequent measurement is permitted using either the amortization method or the fair value measurement method for each class of separately recognized servicing assets and servicing liabilities.

     SFAS No. 156 is effective as of the beginning of an entity's first fiscal year that begins after September 15, 2006 (year ending December 31, 2007 for Pepco Holdings). Application is to be applied prospectively to all transactions following adoption of SFAS No. 156. Pepco Holdings has evaluated the impact of SFAS No. 156 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, or cash flows.

     FSP FIN 46(R)-6, "Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)"

     In April 2006, the FASB issued FSP FASB Interpretation Number (FIN) 46(R)-6, "Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)" (FSP FIN 46(R)-6), which provides guidance on how to determine the variability to be considered in applying FIN 46(R), "Consolidation of Variable Interest Entities."

     The guidance in FSP FIN 46(R)-6 is applicable prospectively beginning the first day of the first reporting period beginning after June 15, 2006.

     Pepco Holdings started applying the guidance in FSP FIN 46(R)-6 to new and modified arrangements effective July 1, 2006.

     EITF Issue No. 06-3, "Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions"

     On June 28, 2006, the FASB ratified EITF Issue No. 06-3, "Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions" (EITF 06-3). EITF 06-3 provides guidance on an entity's disclosure of its accounting policy regarding the gross or net presentation of certain taxes and provides that if taxes included in gross revenues are significant, a company should disclose the amount of such taxes for each period for which an income statement is presented (i.e., both interim and annual periods). Taxes within the scope of EITF 06-3 are those that are imposed on and concurrent with a specific

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revenue-producing transaction. Taxes assessed on an entity's activities over a period of time are not within the scope of EITF 06-3. EITF 06-3 is effective for interim and annual reporting periods beginning after December 15, 2006 (March 31, 2007 for Pepco Holdings) although earlier application is permitted.

     Pepco Holdings does not anticipate that the adoption of EITF 06-3 will materially impact its disclosure requirements.

     FSP FAS 13-2, "Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction"

     On July 13, 2006, the FASB issued FSP FAS 13-2, "Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction" (FSP FAS 13-2). FSP FAS 13-2, which amends SFAS No. 13, "Accounting for Leases," addresses how a change or projected change in the timing of cash flows relating to income taxes generated by a leveraged lease transaction affects the accounting by a lessor for that lease.

     FSP FAS 13-2 will not be effective until the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for Pepco Holdings). A material change in the timing of cash flows under PHI's cross-border leases as the result of a settlement with the Internal Revenue Service or a change in tax law would require an adjustment to the book value of the leases and a charge to earnings equal to the repricing impact of the disallowed deductions which could result in a material adverse effect on PHI's financial condition, results of operations, and cash flows.

     FIN 48, "Accounting for Uncertainty in Income Taxes"

     On July 13, 2006, the FASB issued FIN 48, "Accounting for Uncertainty in Income Taxes" (FIN 48). FIN 48 clarifies the criteria for recognition of tax benefits in accordance with SFAS No. 109, "Accounting for Income Taxes," and prescribes a financial statement recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Specifically, it clarifies that an entity's tax benefits must be "more likely than not" of being sustained prior to recording the related tax benefit in the financial statements. If the position drops below the "more likely than not" standard, the benefit can no longer be recognized. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.

     FIN 48 is effective the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for Pepco Holdings). Pepco Holdings has completed its evaluation of FIN 48, which resulted in an immaterial impact to its retained earnings at January 1, 2007, and no impact on its results of operations and cash flows.

     SFAS No. 157, "Fair Value Measurements"

     In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" (SFAS No. 157) which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of this Statement

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will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements.

     SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (year ending December 31, 2008 for Pepco Holdings).

     Pepco Holdings is currently in the process of evaluating the impact of SFAS No. 157 on its financial condition, results of operations and cash flows.

     FSP AUG AIR-1, "Accounting for Planned Major Maintenance Activities"

     On September 8, 2006, the FASB issued FSP AUG AIR-1, which prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. FSP AUG AIR-1 is effective the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for Pepco Holdings).

     Pepco Holdings does not believe that the implementation of FSP AUG AIR-1 will have a material impact on its financial condition, results of operations and cash flows.

     "Staff Accounting Bulletin No. 108"

     On September 13, 2006, the SEC issued SAB No. 108 (SAB 108) which expresses the SEC staff's views on the process of quantifying financial statement misstatements. SAB 108 requires that registrants quantify the impact of correcting all misstatements, including both the carryover and reversing effects of prior year misstatements, on the current year financial statements by quantifying an error using both the rollover and iron curtain approaches and by evaluating the error measured under each approach. Under SAB 108, a registrant's financial statements would require adjustment when either approach results in a material misstatement, after considering all relevant quantitative and qualitative factors. Further, the SEC believes that a registrant's materiality assessment of an identified unadjusted error should quantify the effects of the identified unadjusted error on each financial statement and related financial statement disclosure. SAB 108 is effective for fiscal years endi ng on or after November 15, 2006.

     Pepco Holdings implemented the guidance provided in SAB 108 during the year ended December 31, 2006.

     EITF Issue No. 06-5, "Accounting for Purchases of Life Insurance -- Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of Life Insurance"

     On September 20, 2006, the FASB ratified EITF Issue No. 06-5, "Accounting for Purchases of Life Insurance -- Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of Life Insurance" (EITF 06-5) which provides guidance on whether an entity should consider the contractual ability to surrender all of the individual-life policies (or certificates under a group life policy) together when determining the amount that could be realized in accordance with FTB 85-4, and whether a guarantee of the additional value associated with the group life policy affects that determination. EITF 06-5 provides that a policyholder should (i) determine the amount that could be realized under the insurance contract assuming the surrender of an individual-life by individual-life policy (or certificate by certificate in a group policy) and (ii) not discount the cash surrender value component of the amount that could be realized when c ontractual restrictions on the ability to

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surrender a policy exist unless contractual limitations prescribe that the cash surrender value component of the amount that could be realized is a fixed amount, in which case the amount that could be realized should be discounted in accordance with Opinion 21. EITF 06-5 is effective for fiscal years beginning after December 15, 2006 (year ending December 31, 2007 for Pepco Holdings).

     Pepco Holdings does not anticipate that the adoption of EITF 06-5 will materially impact its disclosure requirements.

     FASB Staff Position No. EITF 00-19-2, "Accounting for Registration Payment Arrangements"

     On December 21, 2006, the FASB issued FSP No. EITF 00-19-2, "Accounting for Registration Payment Arrangements"(FSP EITF 00-19-2), which addresses an issuer's accounting for registration payment arrangements and specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB SFAS No. 5, "Accounting for Contingencies." FSP EITF 00-19-2 is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to the date of its issuance. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to the issuance of FSP EITF 00-19-2, this guidance shall be effe ctive for financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years (December 31, 2007 for Pepco Holdings).

     Pepco Holdings is evaluating the impact, if any, of FSP EITF 00-19-2 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, or cash flows.

      SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115"

     On February 15, 2007, the FASB issued SFAS No.159, "The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115" (SFAS No. 159) which permits entities to choose to elect to measure eligible financial instruments at fair value. The objective of SFAS No. 159 is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of SFAS No. 159 will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements.

     SFAS No.159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company's choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair

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value on the face of the balance sheet. SFAS No. 159 does not eliminate disclosure requirements included in other accounting standards.

     SFAS No. 159 applies to fiscal years beginning after November 15, 2007 (year ending December 31, 2008 for Pepco Holdings), with early adoption permitted for an entity that has also elected to apply the provisions of SFAS No. 157, Fair Value Measurements.An entity is prohibited from retrospectively applying SFAS No. 159, unless it chooses early adoption. SFAS No. 159 also applies to eligible items existing at November 15, 2007 (or early adoption date). Pepco Holdings is in the process of evaluating the impact of SFAS No. 159 on its financial condition, results of operations and cash flows.

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 of 1934, as amended, and are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding Pepco Holdings' intents, beliefs and current expectations. In some cases, you can identify forward-looking statements by terminology such as "may," "will," "should," "expects," "plans," "anticipates," "believes," "estimates," "predicts," "potential" or "continue" or the negative of such terms or other comparable terminology. Any forward-looking statements are not guarantees of future performance, and actual results could differ materially from those indicated by the forward-looking statements. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause PHI's or PHI's industry's a ctual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements.

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

·	Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;
·	Changes in and compliance with environmental and safety laws and policies;
·	Weather conditions;
·	Population growth rates and demographic patterns;
·	Competition for retail and wholesale customers;
·	General economic conditions, including potential negative impacts resulting from an economic downturn;
·	Growth in demand, sales and capacity to fulfill demand;
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·	Changes in tax rates or policies or in rates of inflation;
·	Changes in accounting standards or practices;
·	Changes in project costs;
·	Unanticipated changes in operating expenses and capital expenditures;
·	The ability to obtain funding in the capital markets on favorable terms;
·	Rules and regulations imposed by Federal and/or state regulatory commissions, PJM and other regional transmission organizations (NY ISO, ISO New England), the North American Electric Reliability Council and other applicable electric reliability organizations;
·	Legal and administrative proceedings (whether civil or criminal) and settlements that affect PHI's business and profitability;
·	Pace of entry into new markets;
·	Volatility in market demand and prices for energy, capacity and fuel;
·	Interest rate fluctuations and credit market concerns; and
·	Effects of geopolitical events, including the threat of domestic terrorism.

     Any forward-looking statements speak only as to the date of this 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.

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

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

POTOMAC ELECTRIC POWER COMPANY

GENERAL OVERVIEW

     Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in Washington, D.C. and major portions of Montgomery County and Prince George's County in suburban Maryland. Pepco provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier, in both the District of Columbia and Maryland. Default Electricity Supply is known as Standard Offer Service (SOS) in both the District of Columbia and Maryland. Pepco's service territory covers approximately 640 square miles and has a population of approximately 2.1 million. As of December 31, 2006, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to Washington, D.C. customers.

     Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (PHI or Pepco Holdings). Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between PHI and Pepco and certain activities of Pepco are subject to the regulatory oversight of Federal Energy Regulatory Commission under PUHCA 2005.

RESULTS OF OPERATIONS

     The following results of operations discussion is for the year ended December 31, 2006 compared to the year ended December 31, 2005. Other than this disclosure, information under this item has been omitted in accordance with General Instruction I(2)(a) to the Form 10-K. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2006		2005		Change
Regulated T&D Electric Revenue	$	854.1	$	885.3	$	(31.2)
Default Supply Revenue		1,331.7		929.8		401.9
Other Electric Revenue		30.7		30.2		.5
Total Operating Revenue	$	2,216.5	$	1,845.3	$	371.2

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

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     Regulated T&D Electric

Regulated T&D Electric Revenue	2006		2005		Change
Residential	$	244.7	$	253.4	$	(8.7)
Commercial		501.8		513.9		(12.1)
Industrial		-		-		-
Other (Includes PJM Interconnection LLC (PJM))		107.6		118.0		(10.4)
Total Regulated T&D Electric Revenue	$	854.1	$	885.3	$	(31.2)

Regulated T&D Electric Sales   (gigawatt hours (Gwh))	2006		2005		Change
Residential		7,694		8,024		(330)
Commercial		18,632		19,407		(775)
Industrial		-		-		-
Other		162		163		(1)
Total Regulated T&D Electric Sales		26,488		27,594		(1,106)

Regulated T&D Electric Customers (000s)	2006		2005		Change
Residential		680		674		6
Commercial		73		73		-
Industrial		-		-		-
Other		-		-		-
Total Regulated T&D Electric Customers		753		747		6

     Regulated T&D Electric Revenue decreased by $31.2 million primarily due to the following: (i) $24.6 million decrease due to lower weather-related sales, the result of a 15% decrease in Heating Degree Days and 11% decrease in Cooling Degree Days in 2006, (ii) $9.8 million decrease in network transmission revenues due to a decrease in PJM zonal transmission rates, (iii) $7.1 million decrease in estimated unbilled revenue due to an adjustment recorded in the fourth quarter of 2005, primarily reflecting a modification of the estimation process (including $3.3 million of tax pass-throughs), offset by (iv) $7.6 million increase due to customer growth of 0.8%, and (v) $7.4 million increase primarily due to differences in consumption among the various customer rate classes.

     Default Electricity Supply

Default Supply Revenue	2006		2005		Change
Residential	$	611.8	$	470.1	$	141.7
Commercial		712.6		455.0		257.6
Industrial		-		-		-
Other (Includes PJM)		7.3		4.7		2.6
Total Default Supply Revenue	$	1,331.7	$	929.8	$	401.9

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Default Electricity Supply Sales (Gwh)	2006		2005		Change
Residential		7,269		7,446		(177)
Commercial		8,160		7,170		990
Industrial		-		-		-
Other		33		60		(27)
Total Default Electricity Supply Sales		15,462		14,676		786

Default Electricity Supply Customers (000s)	2006		2005		Change
Residential		652		641		11
Commercial		54		61		(7)
Industrial		-		-		-
Other		-		-		-
Total Default Electricity Supply        Customers		706		702		4

    Default Supply Revenue increased by $401.9 million primarily due to: (i) $346.7 million in higher retail energy rates, primarily resulting from new market based rates in the District of Columbia, in February 2005 and June 2006, and in Maryland June 2006, (ii) $78.2 million increase due to higher Default Electricity Supply sales in 2006, offset by (iii) $40.9 million decrease due to weather-related sales, the result of 15% decrease in Heating Degree Days and 11% decrease in Cooling Degree Days in 2006 (partially offset in Fuel and Purchased Energy expense).

     For the year ended December 31, 2006, Pepco's Maryland customers served by Pepco represented 60% of Pepco's total Maryland sales, and Pepco's District of Columbia customers served by Pepco represented 57% of Pepco's total District of Columbia sales. For the year ended December 31, 2005, Pepco's Maryland customers served by Pepco represented 62% of Pepco's total Maryland sales, and Pepco's District of Columbia customers served by Pepco represented 41% of Pepco's total District of Columbia sales.

Operating Expenses

     Fuel and Purchased Energy

     Fuel and Purchased Energy associated with Default Electricity Supply sales increased by $386.0 million to $1,299.7 million in 2006, from $913.7 million in 2005. The increase is primarily due to: (i) $337.3 million increase in average energy costs, the result of new supply contracts in June 2006 and 2005, (ii) $116.4 million increase due to increased Default Electricity Supply load in 2006, partially offset by (iii) $69.5 million decrease in sales and rate variances, primarily due to weather and customer usage (partially offset in Default Supply Revenue).

     Other Operation and Maintenance

     Other Operation and Maintenance expenses decreased by $3.0 million to $277.3 million in 2006, from $280.3 million in 2005. The decrease was primarily due to the following: (i) $7.0 million decrease in legal expenses primarily related to Mirant Corporation and its predecessors and its subsidiaries (Mirant), (ii) $5.6 million decrease in corporate allocations, (iii) $3.9 million decrease due to a write-off of software in 2005, offset by (iv) $5.2 million increase in Default

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Electricity Supply costs (partially deferred and recoverable), (v) $4.9 million increase due to the 2005 Mirant uncollectible reserve reduction, and (vi) $4.0 million increase in information technology business systems costs.

     Depreciation and Amortization

     Depreciation and Amortization expenses increased by $4.4 million to $166.2 million in 2006, from $161.8 million in 2005 primarily due to plant additions.

     Other Taxes

     Other Taxes decreased by $3.0 million to $273.1 million in 2006, from $276.1 million in 2005. The decrease was primarily due to (i) $7.2 million decrease due to lower pass-throughs, resulting from lower Gwh sales (partially offset in Regulated T&D Revenue), partially offset by (ii) a $4.8 million District of Columbia delivery tax adjustment that corrected amounts that were previously recorded.

     Gain on Sales of Assets

    The Gain on Sales of Assetsof $72.4 million in 2005 primarily resulted from a $68.1 million gain from the sale of non-utility land located at Buzzard Point in the District of Columbia.

     Gain on Settlement of Claims with Mirant

     The Gain on Settlement of Claims with Mirant of $70.5 million in 2005 represents a settlement (net of customer sharing) with Mirant of Pepco's $105 million allowed, pre-petition general unsecured claim against Mirant ($70 million gain) and a Pepco asbestos claim against the Mirant bankruptcy estate ($.5 million gain). See "Regulatory and Other Matters - Relationship with Mirant Corporation" for additional information.

Other Income (Expenses)

     Other Expenses decreased by $6.3 million to a net expense of $57.4 million in 2006, from a net expense of $63.7 million in 2005. This decrease was primarily due to a decrease in interest expense resulting from debt maturities.

Income Tax Expense

     Pepco's effective tax rate for the year ended December 31, 2006 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 and amortization differences, partially offset by the flow-through of tax credits and the flow-through of certain asset removal costs.

     Pepco's effective tax rate for the year ended December 31, 2005 was 44% 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 and amortization differences, and changes in estimates related to tax liabilities of prior tax years subject to audit (primarily due to the mixed service costs issued under Internal Revenue Service Revenue Ruling 2005-53), partially offset by the flow-through of tax credits.

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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 of 1934, as amended, and are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding Pepco's intents, beliefs and current expectations. In some cases, you can identify forward-looking statements by terminology such as "may," "will," "should," "expects," "plans," "anticipates," "believes," "estimates," "predicts," "potential" or "continue" or the negative of such terms or other comparable terminology. Any forward-looking statements are not guarantees of future performance, and actual results could differ materially from those indicated by the forward-looking statements. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause Pepco's or Pepco's industry's actua l results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements.

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

·	Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;
·	Changes in and compliance with environmental and safety laws and policies;
·	Weather conditions;
·	Population growth rates and demographic patterns;
·	Competition for retail and wholesale customers;
·	General economic conditions, including potential negative impacts resulting from an economic downturn;
·	Growth in demand, sales and capacity to fulfill demand;
·	Changes in tax rates or policies or in rates of inflation;
·	Changes in 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 Federal and/or state regulatory commissions;
·	Legal and administrative proceedings (whether civil or criminal) and settlements that affect Pepco's business and profitability;
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·	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 Pepco's business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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

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

DELMARVA POWER & LIGHT COMPANY

GENERAL OVERVIEW

     Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and Virginia. DPL provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is also known as Default Service in Virginia, as Standard Offer Service (SOS) in Maryland and in Delaware on and after May 1, 2006, and as Provider of Last Resort service in Delaware before May 1, 2006. DPL's electricity distribution service territory covers approximately 6,000 square miles and has a population of approximately 1.3 million. As of December 31, 2006, approximately 65% of delivered electricity sales were to Delaware customers, approximately 32% were to Maryland customers, and approximately 3% were to Virginia customers. DPL also provides natural gas distribution servic e in northern Delaware. DPL's natural gas distribution service territory covers approximately 275 square miles and has a population of approximately .5 million.

     DPL is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (PHI or Pepco Holdings). Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between PHI and DPL and certain activities of DPL are subject to the regulatory oversight of Federal Energy Regulatory Commission under PUHCA 2005.

RESULTS OF OPERATIONS

     The following results of operations discussion is for the year ended December 31, 2006 compared to the year ended December 31, 2005. Other than this disclosure, information under this item has been omitted in accordance with General Instruction I(2)(a) to the Form 10-K. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2006		2005		Change
Regulated T&D Electric Revenue	$	333.4	$	382.6	$	(49.2)
Default Supply Revenue		812.5		676.2		136.3
Other Electric Revenue		22.1		23.5		(1.4)
Total Electric Operating Revenue	$	1,168.0	$	1,082.3	$	85.7

     The table above shows the amount of Electric Operating Revenue earned that is subject to price regulation (Regulated Transmission and Distribution (T&D) Electric Revenue and Default Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue). Regulated T&D Electric Revenue includes revenue DPL receives for delivery of electricity to its customers, for which DPL is paid regulated rates. Default Supply Revenue is the revenue received from Default Electricity Supply. The costs related to the supply of electricity are included in Fuel and Purchased Energy expense. Other Electric Revenue includes revenue for

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work and services performed on behalf of customers including other utilities that is not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rents, late payments, and collection fees.

     Regulated T&D Electric

Regulated T&D Electric Revenue	2006		2005		Change
Residential	$	162.5	$	183.7	$	(21.2)
Commercial		90.0		104.4		(14.4)
Industrial		13.5		20.7		(7.2)
Other (Includes PJM Interconnection, LLC (PJM))		67.4		73.8		(6.4)
Total Regulated T&D Electric Revenue	$	333.4	$	382.6	$	(49.2)

Regulated T&D Electric Sales    (gigawatt hours (Gwh))	2006		2005		Change
Residential		5,170		5,578		(408)
Commercial		5,357		5,410		(53)
Industrial		2,899		3,063		(164)
Other		51		50		1
Total Regulated T&D Electric Sales		13,477		14,101		(624)

Regulated T&D Electric Customers (000s)	2006		2005		Change
Residential		451		449		2
Commercial		60		59		1
Industrial		1		1		-
Other		1		1		-
Total Regulated T&D Electric Customers		513		510		3

     Regulated T&D Electric Revenue decreased by $49.2 million due primarily to: (i) $18.5 million decrease due to a change in Delaware rate structure effective May 1, 2006, which shifted revenue from Regulated T&D Electric Revenue to Default Supply Revenue, (ii) $14.7 million decrease due to lower weather-related sales, the result of a 16% decrease in Heating Degree Days and a 14% decrease in Cooling Degree Days in 2006, (iii) $7.1 million decrease in network transmission revenues due to a decrease in zonal transmission rates, and (iv) $7.0 million decrease due to a Delaware base rate reduction in May 2006.

     Default Electricity Supply

Default Supply Revenue	2006		2005		Change
Residential	$	449.9	$	323.8	$	126.1
Commercial		302.2		261.2		41.0
Industrial		55.4		88.0		(32.6)
Other (Includes PJM)		5.0		3.2		1.8
Total Default Supply Revenue	$	812.5	$	676.2	$	136.3

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Default Electricity Supply Sales (Gwh)	2006		2005		Change
Residential		5,154		5,589		(435)
Commercial		3,472		4,822		(1,350)
Industrial		983		1,720		(737)
Other		49		51		(2)
Total Default Electricity Supply Sales		9,658		12,182		(2,524)

Default Electricity Supply Customers (000s)	2006		2005		Change
Residential		449		449		-
Commercial		53		58		(5)
Industrial		-		1		(1)
Other		1		1		-
Total Default Electricity Supply         Customers		503		509		(6)

     Default Supply Revenue increased $136.3 million due primarily to the following: (i) $248.5 million in higher retail energy rates, primarily resulting from new market based rates beginning May 2006 in Delaware and June 2006 and 2005 in Maryland, (ii) $18.5 million increase due to a change in Delaware rate structure effective May 1, 2006 that shifted revenue from Regulated T&D Electric Revenue to Default Supply Revenue, offset by (iii) $103.2 million decrease due to lower Default Electricity Supply sales in 2006, and (iv) $28.6 million decrease due to weather related sales, the result of a 16% decrease in Heating Degree Days and a 14% decrease in Cooling Degree Days in 2006.

    The following table shows the percentages of DPL's total sales by jurisdiction that are derived from customers receiving Default Electricity Supply in that jurisdiction from DPL.

	2006		2005
Sales to DE customers served by DPL		69%		90%
Sales to MD customers served by DPL		75%		78%
Sales to VA customers served by DPL		94%		100%

Natural Gas Operating Revenue

	2006		2005		Change
Regulated Gas Revenue	$	204.8	$	198.7	$	6.1
Other Gas Revenue		50.6		62.8		(12.2)
Total Natural Gas Operating Revenue	$	255.4	$	261.5	$	(6.1)

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     Regulated Gas

Regulated Gas Revenue	2006		2005		Change
Residential	$	116.2	$	115.0	$	1.2
Commercial		73.0		68.5		4.5
Industrial		10.3		10.6		(.3)
Transportation and Other		5.3		4.6		.7
Total Regulated Gas Revenue	$	204.8	$	198.7	$	6.1

Regulated Gas Sales (billion cubic feet)	2006		2005		Change
Residential		6.6		8.4		(1.8)
Commercial		4.6		5.6		(1.0)
Industrial		.8		1.1		(.3)
Transportation and Other		6.3		5.6		.7
Total Regulated Gas Sales		18.3		20.7		(2.4)

Regulated Gas Customers (000s)	2006		2005		Change
Residential		112		111		1
Commercial		9		9		-
Industrial		-		-		-
Transportation and Other		-		-		-
Total Regulated Gas Customers		121		120		1

     Regulated Gas Revenue increased by $6.1 million primarily due to (i) $33.2 million increase in the Gas Cost Rate (GCR) effective November 2006 and 2005, due to higher natural gas commodity costs (primarily offset in Gas Purchased expense), offset by (ii) $22.3 million decrease due to lower weather-related sales, as a result of a 17% decrease in Heating Degree Days in 2006, and (iii) $4.8 million decrease in other sales and rate variances, primarily due to differences in consumption among various customer rate classes.

     Other Gas Revenue

     Other Gas Revenue decreased by $12.2 million to $50.6 million in 2006 from $62.8 million in 2005 primarily due to lower off-system sales (partially offset in Gas Purchased expense).

Operating Expenses

     Fuel and Purchased Energy

     Fuel and Purchased Energy associated with Default Electricity Supply sales increased by $118.8 million to $816.8 million in 2006 from $698.0 million in 2005. The increase is primarily due to the following: (i) $288.4 million increase in average energy costs, the result of higher cost supply contracts in Maryland in June 2006 and 2005, in Delaware beginning in May 2006 and in Virginia in June 2006, offset by (ii) $105.4 million decrease due to lower Default Electricity Supply sales in 2006, and (iii) $45.3 million decrease in sales and rate variances, primarily due to weather and customer usage.

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     Gas Purchased

     Total Gas Purchased increased by $1.6 million to $198.4 million in 2006, from $196.8 million in 2005. The increase is primarily due to the following: (i) $26.3 million increase from the settlement of financial hedges (entered into as part of DPL's regulated natural gas hedge program), (ii) $12.0 million increase in deferred fuel costs, offset by (iii) $27.1 million decrease in sales primarily due to weather and customer usage, and (iv) $9.6 million decrease in costs associated with lower off-system sales (offset in Regulated Gas Revenue and Other Gas Revenue).

     Other Operation and Maintenance

     Other Operation and Maintenance expenses increased by $4.8 million to $184.9 million in 2006 from $180.1 million in 2005. This increase was primarily due to (i) $4.6 million increase in maintenance and restoration expenses, (ii) $3.2 million increase in Default Electricity Supply costs (partially deferred and recoverable), (iii) $2.3 million increase primarily due to the accrual for a Cambridge, Maryland environmental coal gas liability, partially offset by (iv) $2.8 million decrease in costs related to customer requested work, and (v) $1.9 million decrease in the uncollectible reserve due to a change in estimate.

     Other Taxes

     Other Taxes increased by $2.2 million to $36.6 million in 2006 from $34.4 million in 2005. The increase was primarily due to a $2.0 million increase in property taxes due to higher assessments.

     Gain on Sales of Assets

     The Gain on Sales of Assets was $1.5 million in 2006, compared to $3.6 million in 2005. The gain in 2005 primarily resulted from the sale of non-utility land.

Other Income and Expenses

     Other Expenses (which are net of other income) increased by $6.8 million to a net expense of $36.9 million in 2006 from a net expense of $30.1 million in 2005. The increase primarily related to an increase in interest expense on short-term debt.

Income Tax Expense

     DPL's effective tax rate for the year ended December 31, 2006 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, partially offset by the flow-through of deferred investment tax credits.

     DPL's effective tax rate for the year ended December 31, 2005 was 43% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit), changes in estimates related to tax liabilities of prior tax years subject to audit (primarily due to the mixed service cost issue under Internal Revenue Service Rule 2005-53), and the flow-through of certain book tax depreciation differences, partially offset by the flow-through of deferred investment tax credits.

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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 of 1934, as amended, and are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding DPL's intents, beliefs and current expectations. In some cases, you can identify forward-looking statements by terminology such as "may," "will," "should," "expects," "plans," "anticipates," "believes," "estimates," "predicts," "potential" or "continue" or the negative of such terms or other comparable terminology. Any forward-looking statements are not guarantees of future performance, and actual results could differ materially from those indicated by the forward-looking statements. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause DPL or DPL's industry's actual result s, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements.

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

·	Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;
·	Changes in and compliance with environmental and safety laws and policies;
·	Weather conditions;
·	Population growth rates and demographic patterns;
·	Competition for retail and wholesale customers;
·	General economic conditions, including potential negative impacts resulting from an economic downturn;
·	Growth in demand, sales and capacity to fulfill demand;
·	Changes in tax rates or policies or in rates of inflation;
·	Changes in 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 Federal and/or state regulatory commissions;
·	Legal and administrative proceedings (whether civil or criminal) and settlements that affect DPL's business and profitability;
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·	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 DPL undertakes no obligation to update any forward looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of anticipated events. New factors emerge from time to time, and it is not possible for DPL to predict all of such factors, nor can DPL assess the impact of any such factor on our business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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

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

ATLANTIC CITY ELECTRIC COMPANY

GENERAL OVERVIEW

     Atlantic City Electric Company (ACE) is engaged in the generation, transmission, and distribution of electricity in southern New Jersey. ACE provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is also known as Basic Generation Service (BGS) in New Jersey. ACE's service territory covers approximately 2,700 square miles and has a population of approximately 1.0 million.

     ACE is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (PHI or Pepco Holdings). Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between PHI and ACE and certain activities of ACE are subject to the regulatory oversight of Federal Energy Regulatory Commission under PUHCA 2005.

DISCONTINUED OPERATIONS

     In May 2005, ACE announced that it would auction its electric generation assets, consisting of its ownership interests in the Keystone and Conemaugh generating facilities and its B.L. England generating facility. On September 1, 2006, ACE completed the sale of its interests in the Keystone and Conemaugh generating facilities to Duquesne Light Holdings Inc. for approximately $177.0 million, which was subsequently decreased by $1.6 million based on a post-closing 60-day true-up for applicable items not known at the time of closing. Approximately $81.3 million of the net gain from the sale has been used to offset the remaining regulatory asset balance, which ACE has been recovering in rates, and approximately $49.8 million of the net gain is being returned to ratepayers over a 33-month period as a credit on their bills, which began during the October 2006 billing period. The balance to be repaid to customers is $48.4 million as of December 31, 2006.

     Additionally, on February 8, 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May Holdings, LLC, an affiliate of Rockland Capital Energy Investments, LLC (RC Cape May), for a price of $9.0 million, after adjustment for, among other things, variances in the value of fuel and material inventories at the time of closing, plant operating capacity, the value of certain benefits for transferred employees and the actual closing date. The purchase price will be further adjusted based on a post-closing 60-day true-up for applicable items not known at the time of the closing. In addition, RC Cape May and ACE have agreed to arbitration concerning whether RC Cape May must pay to ACE, as part of the purchase price, an additional $3.1 million remaining in dispute. RC Cape May also assumed certain liabilities associated with the B.L. England generating station, including substantially all environmental liabilities. Not included in the sale are certain sulf ur dioxide (SO₂) and nitrogen oxide (NOx) allowances, including those covered by the administrative consent order (ACO) entered into by ACE on January 24, 2006, as described in Item 1 "Business -- Environmental Matters -- Air Quality Regulation." On October 31, 2006, ACE, RC Cape May and the New Jersey Department of Environmental Protection (NJDEP) signed an amendment to the ACO, pursuant

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to which RC Cape May assumed from ACE, upon closing of the sale, certain obligations under the ACO with respect to the B. L. England facility. In addition, among other conditions, the sale required the entry by RC Cape May into a remediation agreement with NJDEP and NJDEP approval of the transfer of certain environmental permits from ACE to the buyer.

     The sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized. ACE anticipates that approximately $9 million to $10 million of additional regulatory assets related to B.L. England may, subject to New Jersey Board of Public Utilities (NJBPU) approval, be eligible for recovery as stranded costs. The emission allowance credits associated with B. L. England will be monetized for the benefit of ACE's ratepayers pursuant to the NJBPU order approving the sale. Net proceeds from the sale of the plant and monetization of the emission allowance credits, which will be determined after the sale upon resolution of certain adjustments, will be credited to ACE's ratepayers in accordance with the requirements of the New Jersey Electric Discount and Energy Competition Act and NJBPU orders.

     B.L. England comprised a significant component of ACE's generation operations and its potential sale required "discontinued operations" presentation under Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long Lived Assets," on ACE's Consolidated Statements of Earnings for the years ended December 31, 2006, 2005, and 2004. The operations of Keystone and Conemaugh are also reflected as "discontinued operations" for each period presented. Additionally, B.L. England's assets and liabilities are reflected as "held for sale" on ACE's Consolidated Balance Sheet at December 31, 2006.

     The following table summarizes information related to the discontinued operations for the years presented (millions of dollars):

	2006	2005	2004
Operating Revenue	$113.7	$170.3	$119.9
Income Before Income Tax Expense and Extraordinary Item	$    4.4	$    5.2	$    4.8
Net Income	$    2.6	$    3.1	$    2.9

RESULTS OF OPERATIONS

     The following results of operations discussion is for the year ended December 31, 2006 compared to the year ended December 31, 2005. Other than this disclosure, information under this item has been omitted in accordance with General Instruction I(2)(a) to the Form 10-K. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2006		2005		Change
Regulated T&D Electric Revenue	$	345.6	$	355.2	$	(9.6)
Default Supply Revenue		1,014.0		976.7		37.3
Other Electric Revenue		13.7		18.2		(4.5)
Total Operating Revenue	$	1,373.3	$	1,350.1	$	23.2

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

     Regulated T&D Electric

Regulated T&D Electric Revenue	2006		2005		Change
Residential	$	168.5	$	175.8	$	(7.3)
Commercial		107.2		108.5		(1.3)
Industrial		15.1		16.1		(1.0)
Other (Includes PJM Interconnection, LLC (PJM))		54.8		54.8		-
Total Regulated T&D Electric Revenue	$	345.6	$	355.2	$	(9.6)

Regulated T&D Electric Sales     (gigawatt hours (Gwh))	2006		2005		Change
Residential		4,275		4,444		(169)
Commercial		4,389		4,366		23
Industrial		1,220		1,224		(4)
Other		47		46		1
Total Regulated T&D Electric Sales		9,931		10,080		(149)

Regulated T&D Electric Customers (000s)	2006		2005		Change
Residential		474		468		6
Commercial		63		62		1
Industrial		1		1		-
Other		1		1		-
Total Regulated T&D Electric Customers		539		532		7

     Regulated T&D Electric Revenue decreased by $9.6 million primarily due to the following: (i) $11.9 million decrease due to lower weather-related sales, the result of a 17% decrease in Heating Degree Days and 12% decrease in Cooling Degree Days in 2006, and (ii) $4.9 million decrease due to differences in consumption among the various customer rate classes, partially offset by (iii) $4.0 million increase due to an adjustment for estimated unbilled revenue in the second quarter 2005, primarily reflecting higher estimated power line losses, and (iv) $3.4 million increase due to customer growth of 1.3%.

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     Default Electricity Supply

Default Supply Revenue	2006		2005		Change
Residential	$	420.5	$	367.8	$	52.7
Commercial		333.8		278.7		55.1
Industrial		52.8		46.2		6.6
Other (Includes PJM)		206.9		284.0		(77.1)
Total Default Supply Revenue	$	1,014.0	$	976.7	$	37.3

Default Electricity Supply Sales (Gwh)	2006		2005		Change
Residential		4,275		4,456		(181)
Commercial		3,167		3,028		139
Industrial		396		338		58
Other		47		46		1
Total Default Electricity Supply Sales		7,885		7,868		17

Default Electricity Supply Customers (000s)	2006		2005		Change
Residential		474		467		7
Commercial		63		62		1
Industrial		1		1		-
Other		1		1		-
Total Default Electricity Supply Customers		539		531		8

     Default Supply Revenue increased by $37.3 million primarily due to the following: (i) $114.1 million in higher retail energy rates, primarily resulting from new market based BGS increases in New Jersey (partially offset in Fuel and Purchased Energy expense), (ii) $10.8 million increase due to higher Default Electricity Supply sales in 2006, (iii) $8.9 million increase in sales due to customer growth, the result of a 1.5% increase in 2006, (iv) $7.9 million increase due to an adjustment for estimated unbilled revenue in the second quarter 2005, primarily reflecting higher estimated power line losses, partially offset by (v) $85.5 million decrease in wholesale energy revenues from sales of generated and purchased energy (included in Other) due to lower market prices and lower sales in 2006, and (vi) $23.6 million decrease due to weather-related sales, the result of a 17% decrease in Heating Degree Days and 12% decrease in Cooling Degree Days in 2006.

     For the years ended December 31, 2006 and 2005, ACE's customers served energy by ACE represented 78% of ACE's total sales.

Operating Expenses

     Fuel and Purchased Energy

     Fuel and Purchased Energy associated with Default Electricity Supply sales increased by $73.3 million to $924.2 million in 2006, from $850.9 million in 2005. This increase is primarily due to (i) $111.1 million increase in average energy costs, the result of higher cost supply contracts in June 2006 and 2005, partially offset by (ii) $34.8 million decrease in other sales and

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rate variances primarily due to weather and customer usage (partially offset in Default Supply Revenue).

     Other Operation and Maintenance

     Other Operation and Maintenance expenses decreased by $6.8 million to $147.7 million in 2006 from $154.5 million in 2005. The decrease was primarily due to a $3.2 million decrease in corporate allocations and a $2.9 million decrease due to a workers' compensation adjustment.

     Depreciation and Amortization

     Depreciation and Amortization expenses decreased by $10.9 million to $111.3 million in 2006, from $122.2 million in 2005. The decrease is primarily due to (i) $7.7 million lower depreciation due to a change in depreciation technique and rates resulting from a 2005 final rate order issued by the NJBPU.

     Deferred Electric Service Costs

     Deferred Electric Service Costs decreased by $41.6 million to $15.0 million in 2006, from $56.6 million in 2005. The $41.6 million decrease represents (i) $35.9 million net under-recovery associated with New Jersey BGS, NUGs, market transition charges and other restructuring items and (ii) $5.7 million in regulatory disallowances (net of amounts previously reserved) associated with the April 2005 NJBPU settlement agreement. At December 31, 2006, ACE's balance sheet included as a regulatory liability an over-recovery of $164.9 million with respect primarily to these items, which is net of a $46.0 million reserve for items disallowed by the NJBPU in a ruling that is under appeal. The $164.9 million regulatory liability also includes an $81.3 million gain related to the September 1, 2006, sale of ACE's interests in Keystone and Conemaugh.

Other Income (Expenses)

     Other expenses increased by $8.1 million to a net expense of $59.1 million in 2006, from a net expense of $51.0 million in 2005. The increase is primarily due to (i) $4.2 million increase in interest expense related to ACE's deferred electric service costs regulated liability, and (ii) $2.8 million increase due to the Contribution in Aid of Construction tax gross up.

Income Tax Expense

     ACE's effective tax rate, excluding discontinued operations, for the year ended December 31, 2006, was 35% as compared to the federal statutory rate of 35%. The effects of state income taxes (net of federal benefit) were offset by changes in estimates related to tax liabilities of prior tax years subject to audit (which is the primary reason for the decrease in the effective rate as compared to 2005) and the flow-through of deferred investment tax credits.

     ACE's effective tax rate, before extraordinary item and excluding discontinued operations for the year ended December 31, 2005, was 45% as compared to the federal statutory rate of 35%. The major reasons for this difference were state income taxes (net of federal benefit), the flow-through of certain book tax depreciation differences and changes in estimates related to tax liabilities of prior tax years subject to audit (primarily due to the mixed service cost issue under Internal Revenue Service Rule 2005-53), partially offset by the flow-through of deferred investment tax credits.

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Extraordinary Item

     As a result of the April 2005 settlement of ACE's electric distribution rate case, ACE reversed $15.2 million in accruals related to certain deferred costs that are now deemed recoverable. The after-tax credit to income of $9.0 million is classified as an extraordinary gain in the 2005 financial statements since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.

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 of 1934, as amended, and are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding ACE's intents, beliefs and current expectations. In some cases, you can identify forward-looking statements by terminology such as "may," "will," "should," "expects," "plans," "anticipates," "believes," "estimates," "predicts," "potential" or "continue" or the negative of such terms or other comparable terminology. Any forward-looking statements are not guarantees of future performance, and actual results could differ materially from those indicated by the forward-looking statements. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause ACE or ACE's industry's actual result s, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements.

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

·	Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;
·	Changes in and compliance with environmental and safety laws and policies;
·	Weather conditions;
·	Population growth rates and demographic patterns;
·	Competition for retail and wholesale customers;
·	General economic conditions, including potential negative impacts resulting from an economic downturn;
·	Growth in demand, sales and capacity to fulfill demand;
·	Changes in tax rates or policies or in rates of inflation;
·	Changes in project costs;
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·	Unanticipated changes in operating expenses and capital expenditures;
·	The ability to obtain funding in the capital markets on favorable terms;
·	Restrictions imposed by Federal and/or state regulatory commissions;
·	Legal and administrative proceedings (whether civil or criminal) and settlements that affect ACE's business and profitability;
·	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 ACE undertakes no obligation to update any forward looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of anticipated events. New factors emerge from time to time, and it is not possible for ACE to predict all of such factors, nor can ACE assess the impact of any such factor on our business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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

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Item 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES
                         ABOUT MARKET RISK

     Risk management policies for PHI and its subsidiaries are determined by PHI's Corporate Risk Management Committee, the members of which are PHI's Chief Risk Officer, Chief Operating Officer, Chief Financial Officer, General Counsel, Chief Information Officer and other senior executives. The Corporate Risk Management Committee monitors interest rate fluctuation, commodity price fluctuation, and credit risk exposure, and sets risk management policies that establish limits on unhedged risk and determine risk reporting requirements.

Pepco Holdings, Inc.

Commodity Price Risk

     The Competitive Energy segments actively engage in commodity risk management activities to reduce their financial exposure to changes in the value of their assets and obligations due to commodity price fluctuations. Certain of these risk management activities are conducted using instruments classified as derivatives under SFAS No. 133. The Competitive Energy segments also manage commodity risk with contracts that are not classified as derivatives. The Competitive Energy segments' primary risk management objectives are (1) to manage the spread between the cost of fuel used to operate their electric generation plants and the revenue received from the sale of the power produced by those plants by selling forward a portion of their projected plant output and buying forward a portion of their projected fuel supply requirements and (2) to manage the spread between retail sales commitments and the cost of supply used to service those commitments in order to ensure stable and know n minimum cash flows and fix favorable prices and margins when they become available.

     PHI's risk management policies place oversight at the senior management level through the Corporate Risk Management Committee which has the responsibility for establishing corporate compliance requirements for the Competitive Energy businesses' energy market participation. PHI collectively refers to these energy market activities, including its commodity risk management activities, as "other energy commodity" activities and identifies this activity separately from that of the discontinued proprietary trading activity. PHI uses a value-at-risk (VaR) model to assess the market risk of its Competitive Energy segments' energy commodity activities. PHI also uses other measures to limit and monitor risk in its 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 esti mates 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, 2006 (Millions of dollars)
	Proprietary Trading     VaR	VaR for Competitive Energy Activity (1)
95% confidence level, one-day    holding period, one-tailed
Period end	$-	$  5.2
Average for the period	$-	$12.2
High	$-	$23.9
Low	$-	$  4.0

Notes:
(1)	This column represents all energy derivative contracts, normal purchase and sales contracts, modeled generation output and fuel requirements and modeled customer load obligations for the ongoing other energy commodity activities.

     For additional quantitative and qualitative information on the fair value of energy contracts see Note (13) "Use of Derivatives in Energy and Interest Rate Hedging Activities" to the consolidated financial statements of Pepco Holdings included in Item 8.

     A significant portion of the Conectiv Energy's portfolio of electric generating plants consists of "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. Conectiv Energy economically hedges both the estimated plant output and fuel requirements as the estimated levels of output and fuel needs change. Economic hedge percentages include the estimated electricity output of Conectiv Energy's generation plants and any associated financial or physical commodity contracts (including derivative contracts that are classified as cash flow hedges under SFAS No. 133, other derivative instruments, wholesale normal purchase and sales contracts, and load service obligations).

     Conectiv Energy maintains a forward 36 month program with targeted ranges for economically hedging its projected on peak plant output combined with its on-peak energy purchase commitments (based on the then current forward electricity price curve) as follows:

Month	Target Range
1-12	50-100%
13-24	25-75%
25-36	0-50%

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     The primary purpose of the risk management program is to improve the predictability and stability of margins by selling forward a portion of its projected plant output, and buying forward a portion of its projected fuel supply requirements. Within each period, hedged percentages can vary significantly above or below the average reported percentages.

     As of December 31, 2006, the electricity sold forward by Conectiv Energy as a percentage of projected on-peak plant output combined with on-peak energy purchase commitments was 116%, 78%, and 25% for the 1-12 month, 13-24 month and 25-36 month forward periods, respectively. These hedge percentages were above the target ranges for the 1-12 month and 13-24 month periods due to Conectiv Energy's success in the default electricity supply auctions and a decrease in projected on-peak plant output since the forward sale commitments were entered into. The amount of forward on-peak sales during the 1-12 month period represents only 29% of Conectiv Energy's combined total on-peak generating capability and on-peak energy purchase commitments. The volumetric percentages for the forward periods can vary and may not represent the amount of expected value hedged.

     Not all of the value associated with Conectiv Energy's generation activities can be hedged such as the portion attributable to ancillary services and fuel switching due to the lack of market products, market liquidity, and other factors. Also the hedging of locational value and capacity can be limited.

Credit and Nonperformance Risk

     Pepco Holdings' subsidiaries attempt to minimize credit risk exposure to wholesale energy counterparties through, among other things, formal credit policies, regular assessment of counterparty creditworthiness and 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, 2006, credit exposure to wholesale energy counterparties was weighted 55% with investment grade counterparties, 20% with counterparties without external credit quality ratings, and 25% with non-investment grade counterparties.

     This table provides information on the Competitive Energy businesses' credit exposure, net of collateral, to wholesale counterparties.

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Schedule of Credit Risk Exposure on Competitive Wholesale Energy Contracts (Millions of dollars)
	December 31, 2006
Rating (1)	Exposure Before Credit Collateral (2)	Credit Collateral (3)	Net Exposure	Number of Counterparties Greater Than10% (4)	Net Exposure of Counterparties Greater Than 10%
Investment Grade	$76.8	$   -	$76.8
Non-Investment Grade	35.5	1.5	34.0	1	29.8
No External Ratings	30.7	2.5	28.2
Credit reserves			1.2

(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 Investor Service rating of BBB- or Baa3, respectively.
(2)	Exposure before credit collateral - includes the marked to market (MTM) energy contract net assets for open/unrealized transactions, the net receivable/payable for realized transactions and net open positions for contracts not subject to MTM. Amounts due from counterparties are offset by liabilities payable to those counterparties to the extent that legally enforceable netting arrangements are in place. Thus, this column presents the net credit exposure to counterparties after reflecting all allowable netting, but before considering collateral held.
(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).
(4)	Using a percentage of the total exposure.

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 $4.8 million as of December 31, 2006.

Potomac Electric Power Company

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 and variable rate debt was approximately $.8 million as of December 31, 2006.

Delmarva Power & Light Company

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.

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The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term debt and variable rate debt was approximately $1.2 million as of December 31, 2006.

Atlantic City Electric Company

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 and variable rate debt was approximately $.3 million as of December 31, 2006.

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	139	N/A	N/A	N/A
Report of Independent Registered   Public Accounting Firm	140	225	263	295
Consolidated Statements of Earnings	142	226	264	296
Consolidated Statements   of Comprehensive Income	143	227	N/A	N/A
Consolidated Balance Sheets	144	228	265	297
Consolidated Statements of Cash Flows	146	230	267	299
Consolidated Statements   of Shareholders' Equity	147	231	268	300
Notes to Consolidated   Financial Statements	148	232	269	301

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

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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 my deteriorate.

     Management assessed its internal control over financial reporting as of December 31, 2006 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, 2006.

     Management's assessment of the effectiveness of its internal control over financial reporting as of December 31, 2006 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 integrated audits of Pepco Holdings, Inc.'s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, 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, 2006 and December 31, 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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 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 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 6 to the consolidated financial statements, the Company changed the manner in which it accounts for defined benefit pension and other postretirement plans in 2006.

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, 2006 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, 2006, 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&nbs p;on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our

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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 unauthorized acquisition, use, or disposit ion 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 1, 2007

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EARNINGS
For the Year Ended December 31,	2006	2005		2004
(Millions of dollars, except share data)
Operating Revenue
Power Delivery	$5,118.8		$4,702.9	$4,377.7
Competitive Energy	3,160.8		3,288.2	2,755.5
Other	83.3		74.4	89.9
Total Operating Revenue	8,362.9		8,065.5	7,223.1
Operating Expenses
Fuel and purchased energy	5,416.5		4,899.7	4,252.6
Other services cost of sales	649.4		712.3	637.9
Other operation and maintenance	807.3		815.7	796.6
Depreciation and amortization	413.2		427.3	446.2
Other taxes	343.0		342.2	311.4
Deferred electric service costs	22.1		120.2	36.3
Impairment losses	18.9		-	-
Gain on sales of assets	(.8)		(86.8)	(30.0)
Gain on settlement of claims with Mirant	-		(70.5)	-
Total Operating Expenses	7,669.6		7,160.1	6,451.0
Operating Income	693.3		905.4	772.1
Other Income (Expenses)
Interest and dividend income	16.9		16.0	8.7
Interest expense	(339.1)		(337.6)	(373.3)
Income (loss) from equity investments	5.1		(2.2)	14.4
Impairment loss on equity investments	(1.8)		(4.1)	(11.2)
Other income	48.3		50.8	29.3
Other expenses	(11.8)		(8.4)	(9.3)
Total Other Expenses	(282.4)		(285.5)	(341.4)
Preferred Stock Dividend Requirements of Subsidiaries	1.2		2.5	2.8
Income Before Income Tax Expense and Extraordinary Item	409.7		617.4	427.9
Income Tax Expense	161.4		255.2	167.3
Income Before Extraordinary Item	248.3		362.2	260.6
Extraordinary Item (net of tax of $6.2 million)	-		9.0	-
Net Income	$  248.3		$  371.2	$  260.6
Basic and Diluted Share Information
Weighted average shares outstanding	190.7		189.0	176.8
Earnings per share of common stock
Before extraordinary item	$    1.30		$    1.91	$    1.48
Extraordinary item	$          -		$      .05	$          -
Total	$    1.30		$    1.96	$    1.48
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,	2006	2005	2004
(Millions of dollars)
Net income	$248.3	$371.2	$260.6
Other comprehensive (losses) earnings
Unrealized (losses) gains on commodity      derivatives designated as cash flow hedges:
Unrealized holding (losses) gains       arising during period	(143.8)	117.1	(20.9)
Less: reclassification adjustment for               (losses) gains included in net earnings	(2.3)	76.1	33.4
Net unrealized (losses) gains on       commodity derivatives	(141.5)	41.0	(54.3)
Realized gains on Treasury Lock transaction	11.7	11.7	11.7
Unrealized gains (losses) on interest rate swap     agreements designated as cash flow hedges:
Unrealized holding gains (losses) arising       during period	-	1.5	(4.5)
Less: reclassification adjustment for gains (losses)            included in net earnings	-	1.1	(9.6)
Net unrealized gains on interest rate swaps	-	.4	5.1
Unrealized (losses) gains on marketable securities:
Unrealized holding (losses) gains arising       during period	-	-	(3.6)
Less:  reclassification adjustment for gains            included in net earnings	-	-	.8
Net unrealized (losses) gains on marketable       securities	-	-	(4.4)
Minimum pension liability adjustment	(1.2)	(5.2)	(6.9)
Other comprehensive (losses) earnings, before income taxes	(131.0)	47.9	(48.8)
Income tax (benefit) expense	(50.8)	18.7	(19.5)
Other comprehensive (losses) earnings, net of income taxes	(80.2)	29.2	(29.3)
Comprehensive earnings	$168.1	$400.4	$231.3
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, 2006	December 31, 2005
(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents	$      48.8	$     121.5
Restricted cash	12.0	23.0
Accounts receivable, less allowance for     uncollectible accounts of $35.8 million and     $40.6 million, respectively	1,253.5	1,361.4
Fuel, materials and supplies - at average cost	288.8	283.3
Unrealized gains - derivative contracts	72.7	185.7
Prepayments of income taxes	228.4	-
Prepaid expenses and other	77.2	122.8
Total Current Assets	1,981.4	2,097.7
INVESTMENTS AND OTHER ASSETS
Goodwill	1,409.2	1,431.3
Regulatory assets	1,570.8	1,202.0
Investment in finance leases held in Trust	1,321.8	1,297.9
Prepaid pension expense	-	208.9
Other	383.7	432.3
Total Investments and Other Assets	4,685.5	4,572.4
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	11,819.7	11,441.0
Accumulated depreciation	(4,243.1)	(4,072.2)
Net Property, Plant and Equipment	7,576.6	7,368.8
TOTAL ASSETS	$14,243.5	$14,038.9
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, 2006		December 31, 2005
(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt		$     349.6		$     156.4
Current maturities of long-term debt		857.5		469.5
Accounts payable and accrued liabilities		700.7		1,002.2
Capital lease obligations due within one year		5.5		5.3
Taxes accrued		99.9		341.2
Interest accrued		80.1		84.6
Other		433.6		358.4
Total Current Liabilities		2,526.9		2,417.6
DEFERRED CREDITS
Regulatory liabilities		842.7		594.1
Income taxes		2,084.0		1,935.0
Investment tax credits		46.1		51.0
Pension benefit obligation		78.3		36.3
Other postretirement benefit obligations		405.0		284.2
Other		256.5		251.4
Total Deferred Credits		3,712.6		3,152.0
LONG-TERM LIABILITIES
Long-term debt		3,768.6		4,202.9
Transition Bonds issued by ACE Funding		464.4		494.3
Long-term project funding		23.3		25.5
Capital lease obligations		111.1		116.6
Total Long-Term Liabilities		4,367.4		4,839.3
COMMITMENTS AND CONTINGENCIES (NOTE 12)
MINORITY INTEREST		24.4		45.9
SHAREHOLDERS' EQUITY
Common stock, $.01 par value - authorized 400,000,000 shares -     issued 191,932,445 shares and 189,817,723 shares, respectively		1.9		1.9
Premium on stock and other capital contributions		2,645.0		2,586.3
Accumulated other comprehensive loss		(103.4)		(22.8)
Retained earnings		1,068.7		1,018.7
Total Shareholders' Equity		3,612.2		3,584.1
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		$14,243.5		$14,038.9
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,	2006		2005		2004
(Millions of dollars)
OPERATING ACTIVITIES
Net income	$	248.3	$	371.2	$	260.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		413.2		427.3		446.2
Gain on sale of assets		(.8)		(86.8)		(30.0)
Gain on settlement of claims with Mirant		-		(70.5)		-
Gain on sale of other investment		(13.2)		(8.0)		-
Extraordinary item		-		(15.2)		-
Rents received from leveraged leases under income earned		(56.1)		(79.3)		(76.4)
Impairment losses		20.7		4.1		11.2
Deferred income taxes		243.6		(51.6)		217.5
Investment tax credit adjustments		(4.7)		(5.1)		(8.0)
Prepaid pension expense		21.9		(43.2)		.9
Energy supply contracts		(5.1)		(11.3)		(12.3)
Other deferred charges		(94.9)		17.0		3.9
Other deferred credits		18.4		(29.1)		(25.4)
Changes in:
Accounts receivable		225.1		(153.7)		(171.0)
Regulatory assets and liabilities		(31.8)		76.1		(11.3)
Prepaid expenses		4.5		10.3		22.0
Materials and supplies		(8.3)		(76.4)		3.5
Accounts payable and accrued liabilities		(375.3)		327.5		120.4
Interest and taxes accrued		(472.9)		270.7		(36.1)
Proceeds from sale of claims with Mirant		-		112.9		-
Proceeds from Mirant settlement		70.0		-		-
Net Cash From Operating Activities		202.6		986.9		715.7
INVESTING ACTIVITIES
Net investment in property, plant and equipment		(474.6)		(467.1)		(517.4)
Proceeds from/changes in:
Sale of office building and other properties		181.5		84.1		46.4
Sale of Starpower investment		-		-		29.0
Proceeds from sale of marketable securities		-		-		117.6
Purchase of marketable securities		-		-		(98.2)
Purchases of other investments		(.6)		(2.1)		(.3)
Proceeds from sale of other investments		24.2		33.8		15.1
Net investment in receivables		2.2		(7.1)		2.9
Changes in restricted cash		11.0		19.0		(17.8)
Net other investing activities		27.2		5.5		5.4
Net Cash Used By Investing Activities		(229.1)		(333.9)		(417.3)
FINANCING ACTIVITIES
Dividends paid on preferred stock of subsidiaries		(1.2)		(2.5)		(2.8)
Dividends paid on common stock		(198.3)		(188.9)		(176.0)
Common stock issued to the Dividend Reinvestment Plan		29.8		27.5		29.2
Redemption of debentures issued to financing trust		-		-		(95.0)
Redemption of preferred stock of subsidiaries		(21.5)		(9.0)		(53.3)
Redemption of variable rate demand bonds		-		(2.0)		-
Issuance of common stock		17.0		5.7		288.8
Issuances of long-term debt		514.5		532.0		650.4
Reacquisition of long-term debt		(578.0)		(755.8)		(1,119.7)
Issuances (repayments) of short-term debt, net		193.2		(161.3)		136.3
Cost of issuances		(5.6)		(9.0)		(26.7)
Net other financing activities		3.9		2.3		9.7
Net Cash Used By Financing Activities		(46.2)		(561.0)		(359.1)
Net (Decrease) Increase In Cash and Cash Equivalents		(72.7)		92.0		(60.7)
Cash and Cash Equivalents at Beginning of Year		121.5		29.5		90.2
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	48.8	$	121.5	$	29.5
NON-CASH ACTIVITIES
Asset retirement obligations associated with removal costs transferred   to regulatory liabilities	$	78.0	$	(9.9)	$	(3.8)
Excess accumulated depreciation transferred to regulatory liabilities	$	-	$	131.0	$	-
Sale of financed project account receivables	$	-	$	50.0	$	-
Recoverable pension/OPEB costs included in regulatory assets	$	365.4	$	-	$	-
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $3.8 million, $3.8 million   and $2.9 million, respectively) and paid (received) for income taxes:
Interest	$	331.8	$	328.4	$	356.9
Income taxes	$	238.6	$	44.1	$	(19.9)
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) Earnings		Retained Earnings
(Millions of dollars, except shares)
BALANCE, DECEMBER 31, 2003	171,769,448	$  1.7	$2,246.6		$ (3.3)	$(22.7	)	$751.8
Net Income	-	-		-	-	-		260.6
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	)	$836.4
Net Income	-	-		-	-	-		371.2
Other comprehensive income	-	-		-	-	29.2		-
Dividends on common stock   ($1.00/sh.)	-	-		-	-	-		(188.9	)
Reacquisition of subsidiary   preferred stock	-	-		.1	-	-		-
Issuance of common stock:
Original issue shares	261,708	-		5.7	-	-		-
DRP original shares	1,228,505	-		27.5	-	-		-
Reacquired Conectiv and     Pepco PARS	-	-		.3	-	-		-
BALANCE, DECEMBER 31, 2005	189,817,723	$  1.9		$2,599.8	$(13.5)	$(22.8)		$1,018.7
Net Income	-	-		-	-	-		248.3
Other comprehensive income	-	-		-	-	(80.2)		-
Impact of initially applying SFAS No. 158, net of tax	-	-		-	-	(.4)		-
Dividends on common stock   ($1.04/sh.)	-	-		-	-	-		(198.3	)
Reacquisition of subsidiary   preferred stock	-	-		(.4)	-	-		-
Issuance of common stock:
Original issue shares	882,153	-		17.0	-	-		-
DRP original shares	1,232,569	-		29.8	-	-		-
Compensation expense on     share-based awards	-	-		13.1	-	-		-
Treasury stock	-	-		(.8)	-	-		-
BALANCE, DECEMBER 31, 2006	191,932,445	$  1.9		$2,658.5	$(13.5)	$(103.4)		$1,068.7
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. (PHI or Pepco Holdings) is a diversified energy company that, through its operating subsidiaries, is engaged primarily in two principal business operations:

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

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

     PHI was incorporated in Delaware in 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 the combination of DPL and ACE.

     In 2006, the Public Utility Holding Company Act of 1935 (PUHCA 1935) was repealed and was replaced by the Public Utility Holding Company Act of 2005 (PUHCA 2005). As a result, PHI has ceased to be regulated by the Securities and Exchange Commission (SEC) as a public utility holding company and is now subject to the regulatory oversight of the Federal Energy Regulatory Commission (FERC). PHI has notified FERC that it will continue, until further notice, to operate pursuant to the financing order issued by the SEC under PUHCA 1935, which has an authorization period ending June 30, 2008, relating to the issuance of securities and guarantees, other financing transactions and the operation of the money pool by PHI and its subsidiaries that participate in the money pool.

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

     The following is a description of each of PHI's two principal business operations.

Power Delivery

     The largest component of PHI's business is Power Delivery, which consists of the transmission and distribution of electricity and the distribution of natural gas.

     PHI's Power Delivery business is conducted by its three regulated utility subsidiaries: Pepco, DPL and ACE. Each subsidiary is a regulated public utility in the jurisdictions that comprise its service territory. 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 carry electricity to end-use customers in the utility's service territory.

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     Each company is responsible for the delivery of electricity and, in the case of DPL, natural gas in its service territory, for which it is paid tariff rates established by the local public service commission. Each company also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service varies by jurisdiction as follows:

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

     In this Form 10-K, these supply service obligations are referred to generally as Default Electricity Supply.

Competitive Energy

     The Competitive Energy business provides competitive generation, marketing and supply of electricity and gas, and related energy management services, primarily in the mid-Atlantic region. PHI's Competitive Energy operations are conducted through subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv Energy) and Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services). Conectiv Energy and Pepco Energy Services are separate operating segments for financial reporting purposes.

Other Business Operations

     Over the last several years, PHI has discontinued its investments in non-energy related businesses, including the sale of its aircraft investments and the sale of its 50% interest in Starpower Communications LLC (Starpower). Through its subsidiary, Potomac Capital Investment Corporation (PCI), PHI continues to maintain a portfolio of cross-border energy sale-leaseback transactions, with a book value at December 31, 2006 of approximately $1.3 billion. This activity constitutes a fourth operating segment, which is designated as "Other Non-Regulated" for financial reporting purposes.

(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.

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Additionally, undivided interests in several jointly owned electric plants previously held by PHI, and certain transmission and other facilities currently held, are consolidated in proportion to PHI's percentage interest in the facility.

     In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R (revised December 2003), entitled "Consolidation of Variable Interest Entities," (FIN 46R) Pepco Holdings deconsolidated several entities that had previously been consolidated and consolidated several small entities that had not previously been consolidated. FIN 46R addresses 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 46R, see the FIN 46R discussion later in this Note.

Use of Estimates

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP), such as compliance with 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, the calculation of future cash flows and fair value amounts for use in goodwill and asset impairment evaluations, fair value calculations (based on estimated market pricing) associated with derivative instruments, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, an d income tax provisions and reserves. Additionally, PHI is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. PHI records an estimated liability for these proceedings and claims based upon the probable and reasonably estimable criteria contained in Statement of Financial Accounting Standards (SFAS) No. 5 "Accounting for Contingencies." Although Pepco Holdings believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Changes in Accounting Estimates

     During 2005, Pepco recorded the impact of an increase in estimated unbilled revenue (electricity and gas delivered to the customer but not yet billed), primarily reflecting a change in Pepco's unbilled revenue estimation process. This modification in accounting estimate increased net earnings for the year ended December 31, 2005 by approximately $2.2 million.

     During 2005, DPL and ACE each recorded the impact of reductions in estimated unbilled revenue, primarily reflecting an increase in the estimated amount of power line losses (electricity lost in the process of its transmission and distribution to customers). These changes in accounting estimates reduced net earnings for the year ended December 31, 2005 by approximately $7.4 million, of which $1.0 million was attributable to DPL and $6.4 million was attributable to ACE.

     During 2005, Conectiv Energy increased the estimated useful lives of its generation assets which resulted in lower depreciation expense of approximately $5.3 million.

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Revenue Recognition

Regulated Revenue

     The Power Delivery businesses recognize revenue from the supply and delivery of electricity and gas upon delivery to their customers, including amounts for services rendered but not yet billed (unbilled revenue). Pepco Holdings recorded amounts for unbilled revenue of $172.2 million and $198.2 million as of December 31, 2006 and 2005, respectively. These amounts are included in the "accounts receivable" line item in the accompanying Consolidated Balance Sheets. Pepco Holdings' utility subsidiaries calculate unbilled revenue using an output based methodology. This methodology is based on the supply of electricity or gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, distance, temperature, and estimated power line losses, which are inherently uncertain and susceptible to change from period to period, the impact of which could be material.

     The taxes related to the consumption of electricity and gas by the utility customers, such as fuel, energy, or other similar taxes, are components of the tariff rates charged by PHI subsidiaries and, as such, are billed to customers and recorded in Operating Revenues. Accruals for these taxes are recorded in Other Taxes. Excise tax related generally to the consumption of gasoline by PHI and its subsidiaries in the normal course of business is charged to operations, maintenance or construction, and is de minimis.

Competitive Revenue

     The Competitive Energy businesses recognize revenue for the supply and delivery of electricity and gas upon delivery to the customer, including amounts for electricity and gas delivered, 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. Revenue for Pepco Energy Services' energy efficiency construction business is recognized using the percentage-of-completion method of revenue recognition which recognizes revenue as work is completed on the contract, and revenue from its operation and maintenance and other products and services contracts are recognized when earned. Revenue from the Other Non-Regulated business lines are principally re cognized 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.

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). DPL's natural gas transmission's practices are regulated by the U.S. Department of Transportation.

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

     The wholesale power transmission operations of each of Pepco, DPL, and ACE are regulated by FERC.

     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 must be eliminated through a charge to earnings.

     The components of Pepco Holdings' regulatory asset balances at December 31, 2006 and 2005, are as follows:

	2006	2005
	(Millions of dollars)
Securitized stranded costs	$   773.0	$   823.5
Recoverable Pension and OPEB costs	365.4	-
Deferred energy supply costs	6.9	18.3
Deferred recoverable income taxes	130.5	150.5
Deferred debt extinguishment costs	76.9	80.9
Unrecovered purchased power contract costs	13.5	18.2
Deferred other postretirement benefit costs	15.0	17.5
Phase in credits	31.0	-
Asset retirement cost	33.0	-
Other	125.6	93.1
Total regulatory assets	$1,570.8	$1,202.0

     The components of Pepco Holdings' regulatory liability balances at December 31, 2006 and 2005, are as follows:

	2006	2005
	(Millions of dollars)
Deferred income taxes due to customers	$ 69.3	$ 73.2
Deferred energy supply costs	164.9	40.9
Regulatory liability for Federal and   New Jersey tax benefit	34.6	37.6
Generation Procurement Credit, customer sharing   commitment, and other	34.3	76.5
Accrued asset removal costs	322.2	244.2
Excess depreciation reserve	105.8	121.7
Asset retirement obligation	63.2	-
Gain from sale of Keystone and Conemaugh	48.4	-
Total regulatory liabilities	$842.7	$594.1

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     A description for each category of regulatory assets and regulatory liabilities 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) (Transition Bonds). A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. The stranded costs are amortized over the life of the Transition Bonds, which mature between 2010 and 2023.

     Recoverable Pension and OPEB Costs: Represents the funded status of Pepco Holdings' defined benefit pension and other postretirement benefit plans that is probable of recovery in rates under SFAS No. 71 by Pepco, DPL and ACE.

     Deferred Energy Supply Costs: The regulatory liability balances of $164.9 million and $40.9 million for the years ended December 31, 2006 and 2005, respectively, primarily represent deferred costs related to a net over-recovery by ACE connected with the provision of BGS and other restructuring related costs incurred by ACE. This deferral received a return and is being recovered over 8 years beginning in 2007. The regulatory asset balances of $6.9 million and $18.3 million for the years ended December 31, 2006 and 2005, respectively, represent deferred fuel costs for DPL's gas business, which are recovered annually.

     Deferred Recoverable Income Taxes:Represents a receivable from our customers for tax benefits applicable to utility operations of Pepco, DPL, and ACE previously flowed through before the companies were ordered to provide deferred income taxes. As the temporary differences between the financial statement and tax basis of assets reverse, the deferred recoverable balances are reversed. 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 Contract Costs: Represents deferred costs related to purchase power contracts at ACE and DPL. The ACE amortization period began in July 1994 and will end in May 2014. The DPL amortization period began in February 1996 and will end in October 2007. Both earn a return.

     Deferred Other Postretirement Benefit Costs:Represents the non-cash portion of other postretirement 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.

     Phase In Credits: Represents a phase-in credit for participating Maryland and Delaware customers to mitigate the immediate impact of significant rate increases in 2006. The deferral period for Delaware is May 1, 2006 to January 1, 2008, with recovery to occur over a 17-month period beginning January 1, 2008. This deferral will be amortized on a straight-line basis. The deferral period for Maryland is June 1, 2006 to June 1, 2007, with recovery to occur over an 18-month period beginning June 2007. Recovery is rate per kilowatt-hour based on usage during the recovery period.

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     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 generating plants divested by ACE 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: Pepco's settlement agreements related to its December 2000 generation asset 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 from February 8, 2001 through February 7, 2005 in each jurisdiction. The GPC represents the customers' share of profits that Pepco has realized on the procurement and resale of SOS electricity supply to customers in Maryland and the District of Columbia that has not yet been distributed to customers. Pepco is currently distributing the customers' share of profits monthly to customers in a billing credit. The GPC increased by $42.3 million in December 2005 due to the settlement of Pepco's $105 million allowed, pre-petition general unsecured claim against Mirant Corporation and its predecessors and its subsidiaries (Mirant) (the Pepco TPA Clai m).

     Accrued Asset Removal Costs:  Represents Pepco's and DPL's asset retirement obligations associated with removal costs accrued using public service commission-approved depreciation rates for transmission, distribution, and general utility property. In accordance with the SEC interpretation of SFAS No. 143, accruals for removal costs were classified as a regulatory liability.

     Excess Depreciation Reserve: The excess depreciation reserve was recorded as part of a New Jersey rate case settlement. This excess reserve is the result of a change in depreciable lives and a change in depreciation technique from remaining life to whole life. The excess is being amortized over an 8.25 year period, which began in June 2005.

     Asset Retirement Obligation: During the first quarter of 2006, ACE recorded an asset retirement obligation of $60 million for B.L. England plant demolition and environmental remediation costs. Amortization of the liability is over a two-year period amortized quarterly. The cumulative amortization of $33.0 million at December 31, 2006, is recorded as a regulatory asset -- "Asset Retirement Cost." As discussed in Note (12) Commitments and Contingencies -- "ACE Sale of Generating Assets," on February 8, 2007, ACE completed the sale of the B.L. England generating facility.

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     Gain from Sale of Keystone and Conemaugh: On September 1, 2006, ACE completed the sale of its interests in the Keystone and Conemaugh generating facilities to Duquesne Light Holdings Inc. for approximately $177.0 million, which was subsequently decreased by $1.6 million based on a post-closing 60-day true-up for applicable items not known at the time of the closing. Approximately $81.3 million of the net gain from the sale has been used to offset a remaining regulatory asset balance, which ACE has been recovering in rates, and approximately $49.8 million of the net gain is being returned to ratepayers over a 33-month period as a credit on their bills, which began during the October 2006 billing period. The balance to be repaid to customers is $48.4 million as of December 31, 2006.

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 members of which are PHI's Chief Risk Officer, Chief Operating Officer, Chief Financial Officer, General Counsel, Chief Information Officer and other senior executives. The CRMC monitors interest rate fluctuation, commodity price fluctuation, and credit risk exposure, and sets risk management policies that establish limits on unhedged risk and determine risk reporting requirements.

     PHI accounts for its derivative activities in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by subsequent pronouncements. SFAS No. 133 requires derivative instruments to be measured at fair value. Derivatives are recorded on the Consolidated Balance Sheets 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 under SFAS No. 133: (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 does not designate as hedges.

     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. Gains or losses related to any ineffective portion of cash flow hedges are also recognized in earnings immediately.

     Changes in the fair value of 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 under SFAS No. 133. These contracts are designated as "normal purchases and sales" as permitted by SFAS No. 133. This type of contract is used in normal operations, settles

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physically, and follows standard accrual accounting. Unrealized gains and losses on these contracts do not appear on the Consolidated Balance Sheets. Examples of these transactions include purchases of 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 expenses.

     PHI uses option contracts to mitigate certain risks. These options are normally marked-to-market through current earnings because of the difficulty in qualifying options for hedge accounting treatment. Market prices, when available, are used to value options. If market prices are not available, the market value of the options is estimated using Black-Scholes closed form models. Option contracts typically make up only a small portion of PHI's total derivatives portfolio.

     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, internal models are 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.

     The impact of 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 on a net basis in the Consolidated Statements of Earnings. When a hedging gain or loss is realized, it is presented on a net basis in the same category as the underlying item being hedged. Normal purchase and sale transactions are presented gross on the Consolidated Statements 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.

     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 its load supply obligations. 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. Derivatives designated as cash flow and fair value hedges (Accounting Hedges) are matched against each component using the product or products that most closely represent the underlying hedged item. The total portfolio is risk managed based on its megawatt position by month. If the total portfolio becomes too long or too short for a period as determined in accordance with Conectiv Energy's policies, steps are taken to reduce or increase hedges. Portfolio-level hedging includes the use of Accounting Hedges, derivatives that are being marked-to-market through earnings, and other physical commodity purchases and sales.

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     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 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 on the natural gas hedging activity, are fully recoverable through the gas cost rate clause included in DPL's gas tariff rates approved by the DPSC and are deferred under SFAS No. 71 until recovered. At December 31, 2006, DPL had a net deferred derivative payable of $27.3 million, offset by a $28.5 million regulatory asset. At December 31, 2005, DPL ha d a deferred derivative receivable on DPL's balance sheet of $21.6 million, offset by a $21.6 million regulatory liability.

     Pepco Energy Services purchases electric and natural gas futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas and electricity for delivery to customers. Pepco Energy Services accounts for its futures and swap contracts as cash flow hedges of forecasted transactions. Its options contracts are marked-to-market through current earnings. Its forward contracts are accounted for under standard accrual accounting as these contracts meet the requirements for normal purchase and sale accounting under SFAS No. 133.

     PCI has entered into interest rate swap agreements for the purpose of managing its overall borrowing rate and managing its interest rate exposure associated with debt it has issued. As of December 31, 2006, approximately 72.9% of PCI's fixed rate debt for its Medium-Term Note program has been swapped into variable rate debt in a transaction entered into in December 2001, which matures in December 2008. All of PCI's hedges on variable rate debt expired when the variable rate debt incurred under its Medium-Term Note program matured during 2005.

Emission Allowances

     Emission allowances for sulfur dioxide and nitrous oxide are allocated to generation owners by the U.S. Environmental Protection Agency (EPA) based on Federal programs designed to regulate the emissions from power plants. The EPA allotments have no cost basis to the generation owners. Depending on the run-time of a generating unit in a given year, and other pollution controls it may have, the unit may need additional allowances above its allocation or it may have excess allowances. Allowances are traded among companies in an over-the-counter market, which allows companies to purchase additional allowances to avoid incurring penalties for noncompliance with applicable emissions standards or to sell excess allowances.

     Pepco Holdings accounts for emission allowances as inventory in the balance sheet line item "Fuel, materials and supplies - at average cost." Allowances from EPA allocations are added to current inventory each year at a zero basis. Additional purchased allowances are recorded at cost. Allowances sold or consumed at the power plants are expensed at a weighted-average cost. This cost tends to be relatively low due to the zero-basis allowances. At December 31, 2006 and 2005, the book value of emission allowances was $11.7 million and $9.8 million, respectively. Pepco Holdings has established a committee to monitor compliance with emissions regulations and whether its power plants have the required number of allowances.

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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 the 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 at least annually. Substantially all of Pepco Holdings' goodwill was generated by the acquisition of Conectiv by Pepco.

     A roll forward of PHI's goodwill balance follows (millions of dollars):

Balance, December 31, 2004	$1,430.5
Add:  Adjustment to pre-merger tax reserve	.8
Balance, December 31, 2005	1,431.3
Add:  Changes in estimates related to pre-merger tax liabilities	.6
Less: Adjustment due to resolution of pre-merger tax contingencies	(9.1)
Impairment related to completed dispositions	(13.6)
Balance, December 31, 2006	$  1,409.2

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. Pepco Holdings tested its goodwill for impairment as of July 1, 2006. This test 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.

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     For long-lived assets that are expected to be held and used, SFAS No. 144 requires that an impairment loss be recognized only 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 will be recognized to the extent their carrying amount exceeds their fair value including costs to sell.

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 that is restricted from use for general corporate purposes.

Prepaid Expenses and Other

     The prepaid expenses and other balance primarily consists of prepayments and the current portion of deferred income tax assets.

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 after the receivable is recorded). PHI 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. 71, PHI's utility subsidiaries can capitalize as Allowance for Funds Used During Construction (AFUDC) the capital costs of financing the construction of plant and equipment. The debt portion of AFUDC is recorded as a reduction of "interest expense" and the equity portion of AFUDC is credited to "other income" in the accompanying Consolidated Statements of Earnings.

     Pepco Holdings recorded AFUDC for borrowed funds of $2.8 million, $3.3 million, and $2.8 million for the years ended December 31, 2006, 2005, and 2004, respectively.

     Pepco Holdings recorded amounts for the equity component of AFUDC of $3.8 million, $4.7 million and $4.1 million for the years ended December 31, 2006, 2005, and 2004, respectively.

Leasing Activities

     Pepco Holdings accounts for leases 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

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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. Each quarter, PHI reviews the carrying value of each lease, which includes a review of the underlying lease financial assumptions, the timing and collectibility of cash flows, and the credit quality (including, if available, credit ratings) of the lessee. Changes to the underlying assumptions, if any, would be accounted for under SFAS No. 13 and reflected in the carrying value of the lease effective for the quarter within which they occur.

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 subsidiaries are also deferred and amortized over the lives of the new issues.

Pension and Other Postretirement Benefit Plans

     Pepco Holdings sponsors a defined benefit retirement plan that covers substantially all employees of Pepco, DPL, ACE and certain employees of other Pepco Holdings subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through a nonqualified retirement plan and provides certain postretirement health care and life insurance benefits for eligible retired employees.

     Pepco Holdings accounts for the PHI Retirement Plan and nonqualified retirement plans in accordance with SFAS No. 87, "Employers' Accounting for Pensions," and its postretirement health care and life insurance benefits for eligible employees in accordance with SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." PHI's financial statement disclosures are prepared in accordance with SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits," as revised.

     SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other
     Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132 (R)"

     On December 31, 2006, Pepco Holdings implemented SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132 (R)" (SFAS No. 158). SFAS No. 158 requires that companies recognize a net liability or asset to report the funded status of their defined benefit pension and other postretirement benefit plans on the balance sheet. Recognizing the funded status of the company's benefit plans as a net liability or asset will require an offsetting adjustment to accumulated other comprehensive income in shareholders' equity or will be deferred as a regulatory asset or liability if probable of recovery in rates under SFAS No. 71, "Accounting For the Effects of Certain Types of Legislation." SFAS No. 158 does not change how pension and other postretirement benefits are accounted for and reported in the consolidated statements of earnings.

     The incremental effect of applying SFAS No. 158 on Pepco Holdings' consolidated balance sheets was as follows (millions of dollars):

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	Before Application ofSFAS No. 158	Adjustments		After Application ofSFAS No. 158
Prepaid pension assets	$187.0		$(187.0)	$        -
Intangible asset	.1		(.1)	-
Regulatory assets	-		365.4	365.4
Deferred income taxes (a)	5.3		.3	5.6
Liability for pension benefits	307.6		179.0	486.6
Accumulated other comprehensive income	8.0		.4	8.4
(a) Related to additional minimum liability and implementation of SFAS No. 158.

     The estimated net loss for the nonqualified pension plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year is $.9 million. The estimated prior service credit for the nonqualified pension plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year is $.1 million. The estimated net loss for the defined benefit pension and postretirement benefit plans that will be amortized from regulated assets into net periodic benefit cost over the next fiscal year is $15.0 million. The estimated prior service cost and credit that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year is $1.3 million and $5.5 million, respectively.

     See Note (6), Pensions and Other Postretirement Benefits, for additional information.

Severance Costs

     In 2004, the Power Delivery business reduced its work force through a combination of retirements and targeted reductions. This reduction 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. A roll forward of PHI's severance accrual balance is as follows (millions of dollars):

Balance, December 31, 2004	$     7.1
Accrued during 2005	5.0
Payments during 2005	(9.6)
Balance, December 31, 2005	2.5
Accrued during 2006	7.3
Payments during 2006	(5.2)
Balance, December 31, 2006	$    4.6

     Based on the number of employees that have accepted or are expected to accept the severance packages, substantially all of the severance liability will be paid by the end of 2007. 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

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determination of any gain or loss on disposition. For additional information regarding the treatment of asset removal obligations, see the "Asset Retirement Obligations" section included in this Note.

     The annual provision for depreciation on electric and gas property, plant and equipment is computed on a 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. The table below provides system-wide composite depreciation rates for the years ended December 31, 2006, 2005, and 2004.

	Transmission & Distribution			Generation
	2006	2005	2004	2006		2005	2004
Pepco	3.5%	3.4%	3.5%	-		-	-
DPL	3.0%	3.1%	3.1%	-		-	-
ACE	2.9%	3.1%	3.5%	.3%	(a)	2.4%	2.3%
Conectiv Energy	-	-	-	2.0%		2.2%	2.5%
Pepco Energy Services	-	-	-	9.4%		9.5%	10.4%

(a) Rate reflects the consolidated balance sheet classification of ACE's generation assets as "assets held for sale" in 2006 and therefore no depreciation expense was recorded.

Asset Retirement Obligations

     In accordance with SFAS No. 143, "Accounting for Asset Retirement Obligations" and FIN 47, asset removal costs are recorded as regulatory liabilities. At December 31, 2006, $322.2 million of accrued asset removal costs ($229.5 million for DPL and $92.7 million for Pepco) and at December 31, 2005, $244.2 million of accrued asset removal costs ($179.2 million for DPL and $65.0 million for Pepco) are reflected as regulatory liabilities in the accompanying Consolidated Balance Sheets. Public service commission-approved depreciation rates for ACE do not contain components for the recovery of removal cost; therefore, the recording of asset retirement obligations for ACE associated with accruals for removal cost is not required. Additionally, in 2005, Pepco Holdings recorded conditional asset retirement obligations of approximately $1.5 million. Accretion for 2006 and 2005, which relates to the regulated Power Delivery segment, has been recorded as a regulatory as set.

     During the first quarter of 2006, ACE recorded an asset retirement obligation of $60 million for B.L. England plant demolition and environmental remediation costs. Amortization of the liability is over a two-year period. As discussed in Note (12) Commitments and Contingencies -- "ACE Sale of Generating Assets," on February 8, 2007, ACE completed the sale of the B.L. England generating facility.

Stock-Based Compensation

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

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     Pepco Holdings adopted and implemented SFAS No. 123R, on January 1, 2006, using the modified prospective method. Under this method, Pepco Holdings recognizes compensation expense for share-based awards, modifications or cancellations after the effective date, based on the grant-date fair value. Compensation expense is recognized over the requisite service period. In addition, compensation cost recognized includes the cost for all share-based awards granted prior to, but not yet vested as of, January 1, 2006, measured at the grant-date fair value. A deferred tax asset and deferred tax benefit are also recognized concurrently with compensation expense for the tax effect of the deduction of stock options and restricted stock awards, which are deductible only upon exercise and vesting/release from restriction, respectively. In applying the modified prospective transition method, Pepco Holdings has not restated prior interim and annual financial results and therefore the se prior periods do not reflect the revised recognition of share-based compensation cost as required by SFAS No. 123R.

     In November 2005, the FASB issued FASB Staff Position (FSP) 123(R)-3, "Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards" (FSP 123R-3). FSP 123R-3 provides an elective alternative transition method that includes a computation that establishes the beginning balance of the additional paid-in capital (APIC pool) related to the tax effects of employee and director stock-based compensation, and a simplified method to determine the subsequent impact on the APIC pool of employee and director stock-based awards that are outstanding upon adoption of SFAS No. 123R. Entities may make a one-time election to apply the transition method discussed in FSP 123R-3. That one-time election may be made within one year of an entity's adoption of SFAS No. 123R, or the FSP's effective date (November 11, 2005), whichever is later. Pepco Holdings adopted the alternative transition method at December 31, 2006.

     Prior to the adoption of SFAS No. 123R, Pepco Holdings accounted for its share-based employee compensation under the intrinsic value method of expense recognition and measurement prescribed by Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees, and related Interpretations" (APB No. 25). Under this method, compensation expense was recognized for restricted stock awards but not for stock options granted since the exercise price was equal to the grant-date market price of the stock.

     The issuance of SFAS No. 123, "Accounting for Stock-Based Compensation," in 1995 as amended by SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," permitted continued application of APB No. 25, but required tabular presentation of 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. This information for the years ended December 31, 2005 and 2004, is as follows:

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	For the Year Ended December 31,
		2005		2004
	(Millions of dollars, except per share data)
Net Income	$	371.2	$	260.6
Add:  Total stock-based employee compensation expense      included in net income as reported (net of related tax effect      of $1.8 million and $1.7 million, respectively)		2.6		2.6
Deduct: Total stock-based employee compensation expense      determined under fair value based methods for all awards (net      of related tax effect of $2.0 million and $2.5 million, respectively)		(2.8)		(3.8)
Pro forma net income	$	371.0	$	259.4
Basic earnings per share as reported	$	1.96	$	1.48
Pro forma basic earnings per share	$	1.96	$	1.47
Diluted earnings per share as reported	$	1.96	$	1.48
Pro forma diluted earnings per share	$	1.96	$	1.47

     Pepco Holdings estimates the fair value of each stock option award on the date of grant using the Black-Scholes-Merton option pricing model. This model uses assumptions related to expected option term, expected volatility, expected dividend yield and risk-free interest rate. Pepco Holdings uses historical data to estimate option exercise and employee termination within the valuation model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options granted are expected to be outstanding.

     No stock options were granted in 2004, 2005 or 2006.

     No modifications were made to outstanding stock options prior to the adoption of SFAS No. 123R, and no changes in valuation methodology or assumptions in estimating the fair value of stock options have occurred with its adoption.

     There were no cumulative adjustments recorded in the financial statements as a result of this new pronouncement; the percentage of forfeitures of outstanding stock options issued prior to SFAS No. 123R's adoption is estimated to be zero.

     Outstanding stock option awards to purchase 1,500 shares were not vested as of January 1, 2006. The awards vested May 1, 2006. The total compensation cost recorded in 2006 related to the vesting of these options was immaterial.

     Cash received from stock options exercised under all share-based payment arrangements for the years ended December 31, 2006, 2005 and 2004, was $15.9 million, $3.7 million, and $.8 million, respectively. The actual tax benefit realized for the tax deductions resulting from these option exercises totaled $.9 million, $.3 million, and zero, respectively, for the years ended December 31, 2006, 2005 and 2004.

     Pepco Holdings' policy is to issue new shares to satisfy stock option exercises and the vesting of restricted stock awards.

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Accumulated Other Comprehensive (Loss) Earnings

     A detail of the components of Pepco Holdings' Accumulated Other Comprehensive (Loss) Earnings is as follows. For additional information, see the Consolidated Statements of Comprehensive Earnings.

	Commodity Derivatives	Treasury   Lock	Interest Rate Swaps	Marketable Securities	Other (a)	Accumulated Other Comprehensive (Loss) Earnings
	(Millions of dollars)
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)
Balance, December 31, 2004	$   (.5)	$(47.1)	$ (.3)	$    -	$(4.1)	$  (52.0)
Current year change	25.1	7.0	.3	-	(3.2)	29.2
Balance, December 31, 2005	$24.6	$(40.1)	$    -	$    -	$(7.3)	$  (22.8)
Current year change	(86.5)	7.0	-	-	(.7)	(80.2)
Impact of initially applying    SFAS No. 158, net of tax	-	-	-	-	(.4)	(.4)
Balance, December 31, 2006	$(61.9)	$(33.1)	$    -	$    -	$(8.4)	$(103.4)
(a)  Represents an adjustment for nonqualified pension plan minimum liability and the impact of initially applying SFAS No. 158.

     A detail of the income tax (benefit) expense allocated to the components of Pepco Holdings' Other Comprehensive (Loss) Earnings for each year is as follows.

Year Ended	Commodity Derivatives	Treasury   Lock	Interest Rate Swaps	Marketable Securities	Other(a)	Other Comprehensive (Loss) Earnings
	(Millions of dollars)
December 31, 2004	$(21.6)	$  4.5	$ 1.8	$(1.4)	$(2.8)	$(19.5)
December 31, 2005	$  15.9	$  4.7	$   .1	$     -	$(2.0)	$  18.7
December 31, 2006	$(55.0)	$  4.7	$    -	$     -	$(.5)	$(50.8)
(a)  Represents the income tax benefit on an adjustment for nonqualified pension plan minimum liability.

Financial Investment Liquidation

     In October 2005, PCI received $13.3 million in cash related to the liquidation of a preferred stock investment that was written-off in 2001 and recorded an after-tax gain of $8.9 million.

Income Taxes

     PHI and the majority of its subsidiaries file a consolidated Federal income tax return. Federal income taxes are allocated among PHI and the subsidiaries included in its consolidated group pursuant to a written tax sharing agreement which was approved by the SEC in connection with the establishment of PHI as a holding company 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 amounts.

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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 PHI's and its subsidiaries' Federal and state income tax returns.

     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, and 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 preceding discussion under "Regulation of Power Delivery Operations."

     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.

FIN 46R, "Consolidation of Variable Interest Entities"

     Subsidiaries of Pepco Holdings have power purchase agreements (PPAs) with a number of entities, including three contracts between unaffiliated non-utility generators (NUGs) and ACE and an agreement of Pepco with Panda-Brandywine, L.P. (Panda), entered into in 1991, pursuant to which Pepco is obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (Panda PPA). Due to a variable element in the pricing structure of the NUGs and the Panda PPA, the Pepco Holdings' subsidiaries potentially assume the variability in the operations of the plants related to these PPAs and therefore have a variable interest in the counterparties to these PPAs. In accordance with the provisions of FIN 46R, Pepco Holdings continued, during 2006, to conduct exhaustive efforts to obtain information from these four entities, but was unable to obtain sufficient information to conduct the analysis required under FIN 46R to determine whether these four entities were variab le interest entities or if Pepco Holdings' subsidiaries were the primary beneficiary. As a result, Pepco Holdings has applied the scope exemption from the application of FIN 46R for enterprises that have conducted exhaustive efforts to obtain the necessary information, but have not been able to obtain such information.

     Net purchase activities with the counterparties to the NUGs and the Panda PPA for the years ended December 31, 2006, 2005, and 2004, were approximately $403 million, $419 million, and $341 million, respectively, of which approximately $367 million, $381 million, and $312 million, respectively, related to power purchases under the NUGs and the Panda PPA. 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 NUGs because cost recovery will be achieved from ACE's customers through regulated rates.

Impairment Losses

     During 2006, Pepco Holdings recorded pre-tax impairment losses of $18.9 million ($13.7 million after-tax) related to certain energy services business assets owned by Pepco Energy Services. The impairments were recorded as a result of the execution of contracts to sell certain assets and due to the lower than expected production and related estimated cash flows from other

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assets. The fair value of the assets under contracts for sale was determined based on the sales contract price, while the fair value of the other assets was determined by estimating future expected production and cash flows.

Sale of Interest in Cogeneration Joint Venture

     During the first quarter of 2006, Conectiv Energy recognized a $12.3 million pre-tax gain ($7.9 million after-tax) on the sale of its equity interest in a joint venture which owns a wood burning cogeneration facility in California.

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 other miscellaneous liabilities. The $70 million paid pursuant to the Settlement Agreement and Release with Mirant Corporation, its predecessors, its subsidiaries and successors (Mirant) (the Settlement Agreement) was included in the 2006 balance.

Other Deferred Credits

     The other deferred credits balance principally consists of non-current unrealized derivative liabilities and miscellaneous deferred liabilities.

Accounting for Planned Major Maintenance Activities

     In accordance with FSP American Institute of Certified Public Accountants Industry Audit Guide, Audits of Airlines--"Accounting for Planned Major Maintenance Activities" (FSP AUG AIR-1), costs associated with planned major maintenance activities related to generation facilities are accounted for on an as incurred basis.

Reclassifications

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

New Accounting Standards

     FSP FTB 85-4-1, "Accounting for Life Settlement Contracts by Third-Party Investors"

     In March 2006, the FASB issued FSP FASB Technical Bulletin (FTB) 85-4-1, "Accounting for Life Settlement Contracts by Third-Party Investors" (FSP FTB 85-4-1). This FSP provides initial and subsequent measurement guidance and financial statement presentation and disclosure guidance for investments by third-party investors in life settlement contracts. FSP FTB 85-4-1 also amends certain provisions of FASBTechnical Bulletin No. 85-4, "Accounting for Purchases of Life Insurance," andSFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The guidance in FSP FTB 85-4-1 applies prospectively for all new life settlement contracts and is effective for fiscal years beginning after June 15, 2006 (the year ending December 31, 2007 for Pepco Holdings). Pepco Holdings has evaluated the impact of FSP FTB

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85-4-1 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, or cash flows.

     EITF 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

     In September 2005, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty" (EITF 04-13), which addresses circumstances under which two or more exchange transactions involving inventory with the same counterparty should be viewed as a single exchange transaction for the purposes of evaluating the effect of APB Opinion 29, "Accounting for Nonmonetary Transactions." EITF 04-13 is effective for new arrangements entered into, or modifications or renewals of existing arrangements, beginning in the first interim or annual reporting period beginning after March 15, 2006.

     Pepco Holdings implemented EITF 04-13 on April 1, 2006. The implementation did not have a material impact on Pepco Holdings' overall financial condition, results of operations, or cash flows for the second quarter of 2006.

     SFAS No. 155, "Accounting for Certain Hybrid Financial Instruments - an amendment of FASB Statements No. 133 and 140"

     In February 2006, the FASB issued SFAS No. 155, "Accounting for Certain Hybrid Financial Instruments - an amendment of FASB Statements No. 133 and 140" (SFAS No. 155). SFAS No. 155 amends FASB Statements No. 133, "Accounting for Derivative Instruments and Hedging Activities," and No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." SFAS No. 155 resolves issues addressed in Statement 133 Implementation Issue No. D1, "Application of Statement 133 to Beneficial Interests in Securitized Financial Assets." SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity's first fiscal year that begins after September 15, 2006 (year ending December 31, 2007 for Pepco Holdings). Pepco Holdings has evaluated the impact of SFAS No. 155 and does not anticipate that its implementation will have a material impact on its overall financial condition, results of operations, or cash flows.

     SFAS No. 156, "Accounting for Servicing of Financial Assets, an amendment of FASB Statement No. 140"

     In March 2006, the FASB issued SFAS No. 156, "Accounting for Servicing of Financial Assets" (SFAS No. 156), an amendment of SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," with respect to the accounting for separately recognized servicing assets and servicing liabilities. SFAS No. 156 requires an entity to recognize a servicing asset or servicing liability upon undertaking an obligation to service a financial asset via certain servicing contracts, and for all separately recognized servicing assets and servicing liabilities to be initially measured at fair value, if practicable. Subsequent measurement is permitted using either the amortization method or the fair value measurement method for each class of separately recognized servicing assets and servicing liabilities.

     SFAS No. 156 is effective as of the beginning of an entity's first fiscal year that begins after September 15, 2006 (year ending December 31, 2007 for Pepco Holdings). Application is to be applied prospectively to all transactions following adoption of SFAS No. 156. Pepco Holdings

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has evaluated the impact of SFAS No. 156 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, or cash flows.

     FSP FIN 46(R)-6, "Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)"

     In April 2006, the FASB issued FSP FIN 46(R)-6, "Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)" (FSP FIN 46(R)-6), which provides guidance on how to determine the variability to be considered in applying FIN 46(R), "Consolidation of Variable Interest Entities."

     The guidance in FSP FIN 46(R)-6 is applicable prospectively beginning the first day of the first reporting period beginning after June 15, 2006.

     Pepco Holdings started applying the guidance in FSP FIN 46(R)-6 to new and modified arrangements effective July 1, 2006.

     EITF Issue No. 06-3, "Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions"

     On June 28, 2006, the FASB ratified EITF Issue No. 06-3, "Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions" (EITF 06-3). EITF 06-3 provides guidance on an entity's disclosure of its accounting policy regarding the gross or net presentation of certain taxes and provides that if taxes included in gross revenues are significant, a company should disclose the amount of such taxes for each period for which an income statement is presented (i.e., both interim and annual periods). Taxes within the scope of EITF 06-3 are those that are imposed on and concurrent with a specific revenue-producing transaction. Taxes assessed on an entity's activities over a period of time are not within the scope of EITF 06-3. EITF 06-3 is effective for interim and annual reporting periods beginning after December 15, 2006 (March 31, 2007 for Pepco Holdings) although earlier application is permitted.

     Pepco Holdings does not anticipate that the adoption of EITF 06-3 will materially impact its disclosure requirements.

     FSP FAS 13-2, "Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction"

     On July 13, 2006, the FASB issued FSP FAS 13-2, "Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction" (FSP FAS 13-2). FSP FAS 13-2, which amends SFAS No. 13, "Accounting for Leases," addresses how a change or projected change in the timing of cash flows relating to income taxes generated by a leveraged lease transaction affects the accounting by a lessor for that lease.

     FSP FAS 13-2 will not be effective until the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for Pepco Holdings). A material change in the timing of cash flows under PHI's cross-border leases as the result of a settlement with the Internal Revenue Service (IRS) or a change in tax law would require an adjustment to the book value of the leases and a charge to earnings equal to the repricing impact of the disallowed deductions

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which could result in a material adverse effect on PHI's financial condition, results of operations, and cash flows.

     FIN 48, "Accounting for Uncertainty in Income Taxes"

     On July 13, 2006, the FASB issued FIN 48, "Accounting for Uncertainty in Income Taxes" (FIN 48). FIN 48 clarifies the criteria for recognition of tax benefits in accordance with SFAS No. 109, "Accounting for Income Taxes," and prescribes a financial statement recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Specifically, it clarifies that an entity's tax benefits must be "more likely than not" of being sustained prior to recording the related tax benefit in the financial statements. If the position drops below the "more likely than not" standard, the benefit can no longer be recognized. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.

     FIN 48 is effective the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for Pepco Holdings). Pepco Holdings has completed its evaluation of FIN 48, which resulted in an immaterial impact to its retained earnings at January 1, 2007, and no impact on its results of operations and cash flows.

     SFAS No. 157, "Fair Value Measurements"

     In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" (SFAS No. 157) which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of this Statement will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements.

     SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (year ending December 31, 2008 for Pepco Holdings).

     Pepco Holdings is currently in the process of evaluating the impact of SFAS No. 157 on its financial condition, results of operations and cash flows.

     FSP AUG AIR-1, "Accounting for Planned Major Maintenance Activities"

     On September 8, 2006, the FASB issued FSP AUG AIR-1, which prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. FSP AUG AIR-1 is effective the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for Pepco Holdings).

     Pepco Holdings does not believe that the implementation of FSP AUG AIR-1 will have a material impact on its financial condition, results of operations and cash flows.

     "Staff Accounting Bulletin No. 108"

     On September 13, 2006, the SEC issued SAB No. 108 (SAB 108) which expresses the SEC staff's views on the process of quantifying financial statement misstatements. SAB 108 requires that registrants quantify the impact of correcting all misstatements, including both the carryover

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and reversing effects of prior year misstatements, on the current year financial statements by quantifying an error using both the rollover and iron curtain approaches and by evaluating the error measured under each approach. Under SAB 108, a registrant's financial statements would require adjustment when either approach results in a material misstatement, after considering all relevant quantitative and qualitative factors. Further, the SEC believes that a registrant's materiality assessment of an identified unadjusted error should quantify the effects of the identified unadjusted error on each financial statement and related financial statement disclosure. SAB 108 is effective for fiscal years ending on or after November 15, 2006.

     Pepco Holdings implemented the guidance provided in SAB 108 during the year ended December 31, 2006.

     EITF Issue No. 06-5, "Accounting for Purchases of Life Insurance -- Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of Life Insurance"

     On September 20, 2006, the FASB ratified EITF Issue No. 06-5, "Accounting for Purchases of Life Insurance -- Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of Life Insurance" (EITF 06-5) which provides guidance on whether an entity should consider the contractual ability to surrender all of the individual-life policies (or certificates under a group life policy) together when determining the amount that could be realized in accordance with FTB 85-4, and whether a guarantee of the additional value associated with the group life policy affects that determination. EITF 06-5 provides that a policyholder should (i) determine the amount that could be realized under the insurance contract assuming the surrender of an individual-life by individual-life policy (or certificate by certificate in a group policy) and (ii) not discount the cash surrender value component of the amount that could be realized when c ontractual restrictions on the ability to surrender a policy exist unless contractual limitations prescribe that the cash surrender value component of the amount that could be realized is a fixed amount, in which case the amount that could be realized should be discounted in accordance with Opinion 21. EITF 06-5 is effective for fiscal years beginning after December 15, 2006 (year ending December 31, 2007 for Pepco Holdings).

     Pepco Holdings does not anticipate that the adoption of EITF 06-5 will materially impact its disclosure requirements.

     FASB Staff Position No. EITF 00-19-2, "Accounting for Registration Payment Arrangements"

     On December 21, 2006, the FASB issued FSP No. EITF 00-19-2, "Accounting for Registration Payment Arrangements"(FSP EITF 00-19-2), which addresses an issuer's accounting for registration payment arrangements and specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB SFAS No. 5, "Accounting for Contingencies." FSP EITF 00-19-2 is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to the date of its issuance. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to the issuance of FSP EITF 00-19-2, this guidance shall be effe ctive for

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financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years (December 31, 2007 for Pepco Holdings).

     Pepco Holdings is evaluating the impact, if any, of FSP EITF 00-19-2 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, or cash flows.

      SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115"

     On February 15, 2007, the FASB issued SFAS No.159, "The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115" (SFAS No. 159) which permits entities to choose to elect to measure eligible financial instruments at fair value. The objective of SFAS No. 159 is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of SFAS No. 159 will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements.

     SFAS No.159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company's choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. SFAS No. 159 does not eliminate disclosure requirements included in other accounting standards.

     SFAS No. 159 applies to fiscal years beginning after November 15, 2007 (year ending December 31, 2008 for Pepco Holdings), with early adoption permitted for an entity that has also elected to apply the provisions ofSFAS No. 157, Fair Value Measurements.An entity is prohibited from retrospectively applying SFAS No. 159, unless it chooses early adoption. SFAS No. 159 also applies to eligible items existing at November 15, 2007 (or early adoption date). Pepco Holdings is in the process of evaluating the impact of SFAS No. 159 on its financial condition, results of operations and cash flows.

(3)  SEGMENT INFORMATION

     Based on the provisions of SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," Pepco Holdings' management has identified its operating segments at December 31, 2006 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. 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 "Corp. & Other" column. Segment financial information for the years ended December 31, 2006, 2005, and 2004, is as follows.

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		Year Ended December 31, 2006                                                    (Millions of dollars)
			Competitive Energy Segments
		Power Delivery	Conectiv      Energy	Pepco Energy Services	Other Non- Regulated	Corp. & Other(a)	PHI Cons.
Operating Revenue		$5,118.8	$2,157.3(b)	$1,668.9	$90.6	$(672.7)	$  8,362.9
Operating Expense (c)		4,651.0(b)	2,059.7	1,631.2(e)	6.5	(678.8)	7,669.6
Operating Income		467.8	97.6	37.7	84.1	6.1	693.3
Interest Income		12.0	35.4	2.9	170.4	(203.8)	16.9
Interest Expense		180.5	63.8	4.9	201.3	(111.4)	339.1
Other Income		18.6	10.4(d)	1.6	7.9	1.3	39.8
Preferred Stock   Dividends		2.1	-	-	2.5	(3.4)	1.2
Income Taxes		124.5(f)	32.5	16.7	8.4(f)	(20.7)(f)	161.4
Net Income (Loss)		191.3	47.1	20.6	50.2	(60.9)	248.3
Total Assets		8,933.3	1,841.5	617.6	1,595.6	1,255.5	14,243.5
Construction   Expenditures		$   447.2	$    11.8	$      6.3	$          -	$      9.3	$     474.6
Notes:
(a)	Includes unallocated Pepco Holdings' (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date. Additionally, the Total Assets line item in this column includes Pepco Holdings' goodwill balance. Included in Corp. & Other are intercompany amounts of $(674.4) million for Operating Revenue, $(668.2) million for Operating Expense, $(280.8) million for Interest Income, $(278.4) million for Interest Expense, and $(2.5) million for Preferred Stock Dividends.
(b)	Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $460.5 million for the year ended December 31, 2006.
(c)	Includes depreciation and amortization of $413.2 million, consisting of $354.3 million for Power Delivery, $36.3 million for Conectiv Energy, $11.8 million for Pepco Energy Services, $1.8 million for Other Non-Regulated and $9.0 million for Corp. & Other.
(d)	Includes $12.3 million gain ($7.9 million after-tax) on the sale of its equity interest in a joint venture which owns a wood burning cogeneration facility in California.
(e)	Includes $18.9 million of impairment losses ($13.7 million after-tax) related to certain energy services business assets.
(f)	In 2006, PHI resolved certain, but not all, tax matters that were raised in Internal Revenue Service audits related to the 2001 and 2002 tax years. Adjustments recorded related to these resolved tax matters resulted in a $6.3 million increase in net income ($2.5 million for Power Delivery and $5.4 million for Other Non-Regulated, partially offset by an unfavorable $1.6 million impact in Corp. & Other). To the extent that the matters resolved related to tax contingencies from the Conectiv heritage companies that existed at the August 2002 merger date, in accordance with accounting rules, an additional adjustment of $9.1 million ($3.1 million related to Power Delivery and $6.0 million related to Other Non-Regulated) was recorded in Corp. & Other to eliminate the tax benefits recorded by Power Delivery and Other Non-Regulated against the goodwill balance that resulted from the merger. Also during 2006, the total favorable impact of $2.6 million was recorded that resulted from changes in estimates related to prior year tax liabilities subject to audit ($4.1 million for Power Delivery, partially offset by an unfavorable $1.5 million for Corp. & Other).

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		Year Ended December 31, 2005                                                  (Millions of dollars)
			Competitive Energy Segments
		Power Delivery	Conectiv Energy	Pepco Energy Services	Other Non- Regulated	Corp.  & Other(a)	PHI Cons.
Operating Revenue		$4,702.9	$2,603.6 (b)	$1,487.5	$     84.5	$(813.0)	$ 8,065.5
Operating Expense (g)		4,032.1 (b)(e)	2,499.7	1,445.1	(3.8) (f)	(813.0)	7,160.1
Operating Income		670.8	103.9	42.4	88.3	-	905.4
Interest Income		8.3	31.9	2.5	115.2	(141.9)	16.0
Interest Expense		175.0	58.7	5.6	149.1	(50.8)	337.6
Other Income		20.2	3.6	1.7	4.6	6.0	36.1
Preferred Stock    Dividends		2.6	-	-	2.5	(2.6)	2.5
Income Taxes		228.6 (c)	32.6	15.3	12.8	(34.1)	255.2
Extraordinary Item    (net of tax of    $6.2 million)		9.0 (d)	-	-	-	-	9.0
Net Income (Loss)		302.1	48.1	25.7	43.7	(48.4)	371.2
Total Assets		8,738.6	2,227.6	514.4	1,476.9	1,081.4	14,038.9
Construction    Expenditures		$  432.1	$     15.4	$    11.3	$           -	$     8.3	$   467.1
Notes:
(a)	Includes unallocated Pepco Holdings' (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date. Additionally, the Total Assets line item in this column includes Pepco Holdings' goodwill balance. Included in Corp. & Other are intercompany amounts of $(815.7) million for Operating Revenue, $(810.2) million for Operating Expense, $(217.6) million for Interest Income, $(215.4) million for Interest Expense, and $(2.5) million for Preferred Stock Dividends.
(b)	Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $565.3 million for the year ended December 31, 2005.
(c)	Includes $10.9 million in income tax expense related to IRS Revenue Ruling 2005-53. Also refer to Note (12) Commitments and Contingencies for a discussion of the IRS mixed service cost issue.
(d)	Relates to ACE's electric distribution rate case settlement that was accounted for in the first quarter of 2005. This resulted in ACE's reversal of $9.0 million in after-tax accruals related to certain deferred costs that are now deemed recoverable. This amount is classified as extraordinary since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.
(e)	Includes $70.5 million ($42.2 million after-tax) gain (net of customer sharing) from the settlement of the Pepco TPA Claim and the Pepco asbestos claims against the Mirant bankruptcy estate. Also includes $68.1 million gain ($40.7 million after-tax) from the sale of non-utility land owned by Pepco at Buzzard Point.
(f)	Includes $13.3 million gain ($8.9 million after-tax) related to PCI's liquidation of a financial investment that was written off in 2001.
(g)	Includes depreciation and amortization of $427.3 million, consisting of $361.4 million for Power Delivery, $40.4 million for Conectiv Energy, $14.5 million for Pepco Energy Services, $1.7 million for Other Non-Regulated and $9.3 million for Corp. & Other.

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		Year Ended December 31, 2004                                           (Millions of dollars)
			Competitive Energy Segments
		Power Delivery	Conectiv Energy	Pepco Energy Services	Other Non- Regulated	Corp.  & Other(a)	PHI Cons.
Operating Revenue		$4,377.7	$2,409.8 (b)	$1,166.6	$     90.5	$(821.5)	$ 7,223.1
Operating Expense (j)		3,840.7 (b)(c)	2,282.6	1,148.8	(2.5) (d)	(818.6)	6,451.0
Operating Income		537.0	127.2	17.8	93.0	(2.9)	772.1
Interest Income		4.7	9.9	.7	60.8	(67.4)	8.7
Interest Expense		178.1	47.8 (e)	2.8	96.6	48.0	373.3
Other Income		16.0	11.0 (g)	2.5	(6.0) (h)	(.3)	23.2
Preferred Stock   Dividends		2.3	-	-	2.5	(2.0)	2.8
Income Taxes (f)		150.2	40.1	5.3	19.2  (i)	(47.5)	167.3
Net Income (Loss)		227.1	60.2	12.9	29.5	(69.1)	260.6
Total Assets		8,397.6	1,896.5	547.9	1,529.7	1,002.9	13,374.6
Construction   Expenditures		$  479.5	$     11.6	$    21.2	$           -	$     5.1	$    517.4
Notes:
(a)	Includes unallocated Pepco Holdings' (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date. Additionally, the Total Assets line item in this column includes Pepco Holdings' goodwill balance. Included in Corp. & Other are intercompany amounts of $(825.4) million for Operating Revenue, $(820.8) million for Operating Expense, $(29.0) million for Interest Income, $(26.7) million for Interest Expense, and $(2.5) million for Preferred Stock Dividends.
(b)	Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $563.5 million for the year ended December 31, 2004.
(c)	Includes a $14.7 million gain ($8.6 million after-tax) recognized by Power Delivery from the condemnation settlement associated with the transfer of certain distribution assets in Vineland, New Jersey. Also, includes a $6.6 million gain ($3.9 million after-tax) recorded by Power Delivery from the sale of non-utility land during the first quarter of 2004.
(d)	Includes an $8.3 million gain ($5.4 million after-tax) recorded by Other Non-Regulated from the sale of PCI's final three aircraft investments.
(e)	Includes $12.8 million loss ($7.7 million after-tax) associated with the pre-payment of the debt incurred by Conectiv Bethlehem, LLC.
(f)	In February 2004, a local jurisdiction issued final consolidated tax return regulations, which were retroactive to 2001. These regulations provided Pepco Holdings (parent company) and its affiliated companies doing business in this location the guidance necessary 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. The $13.2 million consists of $.8 million for Power Delivery, $1.5 million for Pepco Energy Services, $8.8 million for Other Non-Regulated, and $2.1 million for Corp. & Other.
(g)	Includes an $11.2 million pre-tax gain ($6.6 million after-tax) recognized by Conectiv Energy from the disposition of a joint venture associated with a cogeneration facility.
(h)	Includes an $11.2 million pre-tax impairment charge ($7.3 million after-tax) to reduce the value of PHI's investment in Starpower to $28 million at June 30, 2004.
(i)	Includes a $19.7 million charge related to an IRS settlement.
(j)	Includes depreciation and amortization of $446.2 million, consisting of $373.0 million for Power Delivery, $45.2 million for Conectiv Energy, $11.9 million for Pepco Energy Services, $1.9 million for Other Non-Regulated and $14.2 million for Corp. & Other.

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(4)  LEASING ACTIVITIES

     Financing lease balances were comprised of the following at December 31:

		2006		2005
		(Millions of dollars)
Energy leveraged leases	$	1,321.8	$	1,264.4
Other		-		33.5
Total	$	1,321.8	$	1,297.9

     Pepco Holdings' $1,321.8 million equity investment in energy leveraged leases at December 31, 2006, consists of electric power plants and natural gas distribution networks located outside of the United States. Of this amount, $670.7 million of equity is attributable to facilities located in Austria, $470.2 million in The Netherlands and $180.9 million in Australia.

     The components of the net investment in finance leases at December 31, 2006 and 2005 are summarized below (millions of dollars):

At December 31, 2006:	Leveraged   Leases	Direct   Finance  Leases	Total   Finance  Leases
Scheduled lease payments, net of non-recourse debt	$2,284.6	-	$2,284.6
Residual value	-	-	-
Less:    Unearned and deferred income	(962.8)	-	(962.8)
Investment in finance leases held in trust	1,321.8	-	1,321.8
Less:    Deferred taxes	(682.2)	-	(682.2)
Net Investment in Finance Leases Held in Trust	$   639.6	-	$   639.6
At December 31, 2005:	Leveraged   Leases	Direct   Finance  Leases	Total   Finance  Leases
Scheduled lease payments, net of non-recourse debt	$2,315.4	$24.1	$2,339.5
Residual value	-	12.5	12.5
Less:    Unearned and deferred income	(1,051.0)	(3.1)	(1,054.1)
Investment in finance leases held in trust	1,264.4	33.5	1,297.9
Less:    Deferred taxes	(584.3)	(8.7)	(593.0)
Net Investment in Finance Leases Held in Trust	$  680.1	$24.8	$  704.9

     Income recognized from leveraged leases (included in "Other Operating Revenue") was comprised of the following for the years ended December 31:

	2006	2005	2004
	(Millions of dollars)
Pre-tax earnings from leveraged leases	$88.2	$81.5	$83.5
Income tax expense	25.8	20.6	26.8
Net Income from Leveraged Leases Held in Trust	$62.4	$60.9	$56.7

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     Scheduled lease payments from leveraged leases are net of non-recourse debt. Minimum lease payments receivable from PCI's finance leases for each of the years 2007 through 2011 and thereafter are $3.5 million for 2007, zero for 2008, zero for 2009, $16.0 million for 2010, zero for 2011, and $1,302.3 million thereafter. For a discussion of the Federal tax treatment of cross-border leases, see Note (12) "Commitments and Contingencies."

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 beginning in December 1994 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 $48.7 million, $51.2 million and $46.2 million for the years ended December 31, 2006, 2005, and 2004, respectively.

     The approximate annual commitments under all operating leases are $35.8 million for 2007, $36.6 million for 2008, 2009, 2010, and 2011, and $346.7 million thereafter.

     Capital lease assets recorded within Property, Plant and Equipment at December 31, 2006 and 2005, in millions of dollars, are comprised of the following:

At December 31, 2006	Original Cost	Accumulated Amortization	Net Book Value
Transmission	$  76.0	$ 18.0	$  58.0
Distribution	76.0	18.0	58.0
General	2.6	2.0	.6
Total	$154.6	$ 38.0	$116.6
At December 31, 2005
Transmission	$  76.0	$ 15.7	$  60.3
Distribution	79.7	19.3	60.4
General	2.8	1.6	1.2
Total	$158.5	$ 36.6	$121.9

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     The approximate annual commitments under all capital leases are $15.5 million for 2007, $15.4 million for 2008, $15.2 million for 2009, 2010 and 2011, and $121.9 million thereafter.

(5)  PROPERTY, PLANT AND EQUIPMENT

     Property, plant and equipment is comprised of the following:

At December 31, 2006	Original       Cost	Accumulated Depreciation	Net Book Value
	(Millions of dollars)
Generation	$ 1,811.6	$   608.9	$1,202.7
Distribution	6,285.6	2,321.2	3,964.4
Transmission	1,850.3	680.0	1,170.3
Gas	349.8	97.6	252.2
Construction work in progress	343.5	-	343.5
Non-operating and other property	1,178.9	535.4	643.5
Total	$11,819.7	$4,243.1	$7,576.6
At December 31, 2005
Generation	$ 1,795.1	$  558.4	$1,236.7
Distribution	5,985.5	2,219.9	3,765.6
Transmission	1,773.5	680.4	1,093.1
Gas	339.5	100.7	238.8
Construction work in progress	364.1	-	364.1
Non-operating and other property	1,183.3	512.8	670.5
Total	$11,441.0	$4,072.2	$7,368.8

     The non-operating and other property amounts include balances for general plant, distribution and transmission plant held for future use as well as other property held by non-utility subsidiaries.

     Pepco Holdings' utility subsidiaries use separate depreciation rates for each electric plant account. The rates vary from jurisdiction to jurisdiction.

Asset Sales

     As discussed in Note (12), Commitments and Contingencies, on September 1, 2006, ACE completed the sale of its interest in the Keystone and Conemaugh generating facilities for approximately $177.0 million, which was subsequently decreased by $1.6 million based on a post-closing 60-day true up for applicable items not known at the time of closing.

     Additionally, on February 8, 2007, ACE completed the sale of the B.L. England generating facility for a price of $9.0 million, subject to adjustment.

     In August 2005, Pepco sold for $75 million in cash 384,051 square feet of excess non-utility land owned by Pepco located at Buzzard Point in the District of Columbia. The sale resulted in a pre-tax gain of $68.1 million which was recorded as a reduction of Operating Expenses in the Consolidated Statements of Earnings.

     In 2004, PHI recorded pre-tax gains of $14.7 million from the condemnation settlement with the City of Vineland relating to the transfer of its distribution assets and customer accounts, $8.3 million on the sale of PCI's final three aircraft investments, and $6.6 million on the sale of non-utility land.

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Jointly Owned Plant

     PHI's Consolidated Balance Sheet includes its proportionate share of assets and liabilities related to jointly owned plant. PHI's subsidiaries have ownership interests in 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, 2006 is shown below.

Jointly Owned Plant	Ownership Share	Plant in Service	Accumulated Depreciation	Construction Work in Progress
		(Millions of dollars)
Transmission Facilities	Various	$35.8	$22.4	$ -
Other Facilities	Various	5.1	2.0	-
Total		$40.9	$24.4	$ -

(6)  PENSIONS AND OTHER POSTRETIREMENT BENEFITS

Pension Benefits and Other Postretirement Benefits

     Pepco Holdings sponsors a defined benefit retirement plan (the PHI Retirement Plan) that covers substantially all employees of Pepco, DPL, ACE and certain employees of other Pepco Holdings' subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans.

     Pepco Holdings provides certain postretirement health care and life insurance benefits for eligible retired employees. Certain employees hired on 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 PHI.

    Pepco Holdings accounts for the PHI Retirement Plan and nonqualified retirement plans in accordance with SFAS No. 87, "Employers' Accounting for Pensions," and its postretirement health care and life insurance benefits for eligible employees in accordance with SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." In addition, on December 31, 2006, Pepco Holdings implemented SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132 (R)" (SFAS No. 158) which requires that companies recognize a net liability or asset to report the funded status of their defined benefit pension and other postretirement benefit plans on the balance sheet with an offset to accumulated other comprehensive income in shareholders' equity or a deferral in a regulatory asset or liability if probable of recovery in rates under SFAS No. 71 "Accounting For the Effec ts of Certain Types of Legislation." SFAS No.158 does not change how pension and other postretirement benefits are accounted for and reported in the consolidated statements of earnings. PHI's financial statement disclosures are prepared in accordance with SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits," as revised and amended by SFAS No. 158. Refer to Note (2) "Summary of Significant Accounting Policies -- Pension and Other Postretirement Benefit Plans" for additional information.

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     All amounts in the following tables are in millions of dollars.

At December 31,	Pension Benefits		Other Postretirement Benefits
Change in Benefit Obligation	2006	2005	2006	2005
Benefit obligation at beginning of year	$1,746.0	$1,648.0	$610.2	$593.5
Service cost	40.5	37.9	8.4	8.5
Interest cost	96.9	96.1	34.6	33.6
Amendments	-	-	-	-
Actuarial (gain) loss	(42.4)	81.1	(3.6)	12.8
Benefits paid	(125.7)	(117.1)	(38.4)	(38.2)
Benefit obligation at end of year	$1,715.3	$1,746.0	$611.2	$610.2
Change in Plan Assets
Fair value of plan assets at beginning of year	$1,578.4	$1,523.5	$ 173.7	$ 164.9
Actual return on plan assets	177.8	106.4	23.2	10.0
Company contributions	3.2	65.6	47.7	37.0
Benefits paid	(125.7)	(117.1)	(38.4)	(38.2)
Fair value of plan assets at end of year	$1,633.7	$1,578.4	$ 206.2	$ 173.7
Funded Status at end of year    (plan assets less plan obligations)	$  (81.6)	$(167.6)	$(405.0)	$(436.5)

     The following table provides a reconciliation of the projected benefit obligation, plan assets and funded status of the plans prior to the implementation of SFAS No. 158.

	Pension Benefits		Other Postretirement Benefits
	2006	2005	2006	2005
Fair value of plan assets at end of year	$1,633.7	$1,578.4	$ 206.2	$ 173.7
Benefit obligation at end of year	1,715.3	1,746.0	611.2	610.2
Funded status at end of year	(81.6)	(167.6)	(405.0)	(436.5)
Amounts not recognized:
Unrecognized net actuarial loss	242.8	350.5	167.6	188.6
Unrecognized prior service cost	1.1	1.9	(32.1)	(26.2)
Net amount recognized	$  162.3	$  184.8	$(269.5)	$(274.1)

     The following table provides a reconciliation of the amounts recognized in PHI's Consolidated Balance Sheets as of December 31 prior to the implementation of SFAS No. 158:

	Pension Benefits		Other Postretirement Benefits
	2006	2005	2006	2005
Prepaid benefit cost	$187.0	$208.9	$         -	$         -
Accrued benefit cost	(24.7)	(24.1)	(269.5)	(274.1)
Additional minimum liability for nonqualified plan	(13.4)	(12.2)	-	-
Intangible assets for nonqualified plan	.1	.1	-	-
Accumulated other comprehensive income   for nonqualified plan	13.3	12.1	-	-
Net amount recognized	$162.3	$184.8	$(269.5)	$(274.1)

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     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, 2006 and 2005 prior to the implementation of SFAS No. 158.

	Pension Benefits
	2006	2005
Projected benefit obligation for nonqualified plan	$38.7	$38.6
Accumulated benefit obligation for nonqualified plan	38.1	36.3
Fair value of plan assets for nonqualified plan	-	-

     In 2006 and 2005, 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). The amount of reduction to shareholders' equity (net of income taxes) in 2006 was $8.0 million and in 2005 was $7.3 million. The recording of this reduction did not affect net income, cash flows, or compliance with debt covenants in 2006 or 2005.

     The following table provides the amounts recognized in PHI's Consolidated Balance Sheets as of December 31, 2006 after the implementation of SFAS No. 158:

	Pension Benefits		Other Postretirement Benefits
	2006	2005	2006	2005
Prepaid pension costs	$       -	$208.9	$         -	$         -
Prepaid other postretirement benefit costs	-	-	-	10.1
Intangible asset for nonqualified plan	-	.1	-	-
Regulatory asset	229.9	-	135.5	-
Current liabilities	(3.3)	-	-	-
Pension benefit obligation	(78.3)	(36.3)	-	-
Other postretirement benefit obligations	-	-	(405.0)	(284.2)
Deferred income tax	5.6	4.8	-	-
Accumulated other comprehensive income, net of tax	8.4	7.3	-	-
Net amount recognized	$162.3	$184.8	$(269.5)	$(274.1)

     Amounts included in accumulated other comprehensive income (pre-tax) and regulatory assets at December 31, 2006 after implementation of SFAS No. 158 consist of:

	Pension Benefits	Other Postretirement    Benefits
Unrecognized net actuarial loss	$242.8		$167.6
Unamortized prior service cost (credit)	1.1		(36.6)
Unamortized transition liability	-		4.5
	243.9		135.5
Accumulated other comprehensive income ($8.4 million, net of tax)	14.0		-
Regulatory assets	229.9		135.5
	$243.9		$135.5

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     The table below provides the components of net periodic benefit costs recognized for the years ended December 31.

	Pension Benefits			Other Postretirement Benefits
	2006	2005	2004	2006	2005	2004
Service cost	$  40.5	$  37.9	$  35.9	$   8.4	$  8.5	$  8.6
Interest cost	96.9	96.1	94.7	34.6	33.6	35.4
Expected return on plan assets	(130.0)	(125.5)	(124.2)	(11.5)	(10.9)	(9.9)
Amortization of prior service cost	.8	1.1	1.1	(4.0)	(3.3)	(1.8)
Amortization of net loss	17.5	10.9	6.5	14.3	11.3	11.3
Net periodic benefit cost	$  25.7	$  20.5	$  14.0	$ 41.8	$39.2	$43.6

     The 2006 combined pension and other postretirement net periodic benefit cost of $67.5 million includes $32.1 million for Pepco, $.7 million for DPL and $14.3 million for ACE. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries.

     The 2005 combined pension and other postretirement net periodic benefit cost of $59.7 million includes $28.9 million for Pepco, $(2.0) million for DPL and $16.9 million for ACE. The remaining net periodic benefit cost includes amounts for other PHI subsidiaries.

     The 2004 combined pension and other postretirement net periodic benefit cost of $57.6 million includes $24.1 million for Pepco, $1.0 million for DPL and $17.6 million for ACE. 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:

	Pension Benefits		Other Postretirement Benefits
	2006	2005	2006	2005
Discount rate	6.000%	5.625%	6.000%	5.625%
Rate of compensation increase	4.500%	4.500%	4.500%	4.500%
Health care cost trend rate assumed for next year		n/a	8.00%	8.00%
Rate to which the cost trend rate is assumed to decline    (the ultimate trend rate)			5.00%	5.00%
Year that the rate reaches the ultimate trend rate			2010	2009

     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 (millions of dollars):

	1-Percentage- Point Increase	1-Percentage- Point Decrease
Increase (decrease) on total service and interest cost	$  2.1	$  (1.8)
Increase (decrease) on postretirement benefit obligation	$34.4	$(25.2)

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     The following weighted average assumptions were used to determine the net periodic benefit cost for the years ended December 31:

	Pension Benefits		Other Postretirement Benefits
	2006	2005	2006	2005
Discount rate	5.625%	5.875%	5.625%	5.875%
Expected long-term return on plan assets	8.500%	8.500%	8.500%	8.500%
Rate of compensation increase	4.500%	4.500%	4.500%	4.500%

     A cash flow matched bond portfolio approach to developing a discount rate is used to value SFAS No. 87 and SFAS No. 106 liabilities. The hypothetical portfolio includes high quality instruments with maturities that mirror the benefit obligations.

     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-term horizon, are expected to yield a return on assets of 8.50%.

Plan Assets

     The PHI Retirement Plan weighted average asset allocations at December 31, 2006, and 2005, by asset category are as follows:

Asset Category	Plan Assets at December 31,		Target Plan Asset Allocation	Minimum/   Maximum
	2006	2005
Equity securities	58%	62%	60%	55% - 65%
Debt securities	34%	37%	35%	30% - 50%
Other	8%	1%	5%	0% - 10%
Total	100%	100%	100%

     Pepco Holdings' Other Postretirement plan weighted average asset allocations at December 31, 2006, and 2005, by asset category are as follows:

Asset Category	Plan Assets at December 31,		Target Plan Asset Allocation	Minimum/   Maximum
	2006	2005
Equity securities	64%	67%	60%	55% - 65%
Debt securities	33%	24%	35%	20% - 50%
Other	3%	9%	5%	0% - 10%
Total	100%	100%	100%

     In developing an asset allocation policy for the PHI Retirement Plan and other postretirement 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

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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 characteristics, PHI believes that its risk posture is slightly below average relative to other pe nsion 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 PHI Retirement Plan and the other postretirement 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 or postretirement program assets.

Cash Flows

Contributions - PHI Retirement Plan

     Pepco Holdings' funding policy with regard to the PHI Retirement Plan is to maintain a funding level in excess of 100% with respect to its accumulated benefit obligation (ABO). The PHI Retirement Plan currently meets the minimum funding requirements of the Employment Retirement Income Security Act of 1974 (ERISA) without any additional funding. In 2006 and 2005, PHI made discretionary tax-deductible cash contributions to the plan of zero and $60.0 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 2007; however, PHI may elect to make a discretionary tax-deductible contribution, if required to maintain its plan assets in excess of its ABO.

Contributions - Other Postretirement Benefits

     In 2006 and 2005, Pepco contributed $6.0 million and $3.1 million, respectively, DPL contributed $6.8 million and $6.0 million, respectively, and ACE contributed $6.6 million and $7.0 million, respectively, to the plans. Contributions of $13.5 million and $6.4 million, respectively, were made by other PHI subsidiaries. Assuming no changes to the other postretirement benefit pension plan assumptions, PHI expects similar amounts to be contributed in 2007.

Expected Benefit Payments

     Estimated future benefit payments to participants in PHI's pension and postretirement welfare benefit plans, which reflect expected future service as appropriate, as of December 31, 2006 are as follows (millions of dollars):

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Years	Pension Benefits	Other Postretirement Benefits
2007	$106.2	$  39.7
2008	109.0	41.3
2009	113.9	43.0
2010	116.8	44.3
2011	123.9	45.4
2012 through 2016	653.5	237.3

Medicare Prescription Drug Improvement and Modernization Act of 2003

     On December 8, 2003, the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Medicare Act) became effective. The Medicare Act introduced a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefits 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 that PHI plan actuaries have determined are actuarially equivalent to Medicare Part D. PHI elected to recognize the effects of the Medicare Act during the fourth quarter of 2003, which reduced the accumulated postretirement benefit obligation by approximately $28 million. In 2006, Pepco Holdings received $1.6 million in federal Medicare prescription drug subsidies.

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(7)  DEBT

     LONG-TERM DEBT

     The components of long-term debt are shown below.

			At December 31,
Interest Rate	Maturity		2006		2005
			(Millions of dollars)
First Mortgage Bonds
Pepco:
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)(b)	2013		200.0		200.0
4.65% (a)(b)	2014		175.0		175.0
Variable (a)(b)	2022		109.5		-
6.00% (a)	2022		-		30.0
6.375% (a)	2023		-		37.0
5.375% (a)	2024		-		42.5
5.375% (a)	2024		38.3		38.3
5.75% (a)(b)	2034		100.0		100.0
5.40% (a)(b)	2035		175.0		175.0
ACE:
6.18% - 7.15%	2006 - 2008		51.0		116.0
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
5.60% (a)	2025		4.0		4.0
Variable (a)(b)	2029		54.7		54.7
5.80% (a)(b)	2034		120.0		120.0
5.80% (a)(b)	2036		105.0		-
Amortizing First Mortgage Bonds
DPL:
6.95%	2006 - 2008		7.6		10.5
Total First Mortgage Bonds		$	1,591.6	$	1,554.5
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

(a)	Represents a series ofFirst Mortgage Bonds issued by the indicated company as collateral for an outstanding series of senior notes or tax-exempt bonds issued by the same company. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or tax-exempt bonds are identical to the terms of the collateral First Mortgage Bonds by which it is secured. Payments of principal and interest on a series of senior notes or tax-exempt bonds satisfy the corresponding payment obligations on the related series of collateral First Mortgage Bonds. Because each series of senior notes and tax-exempt bonds and the series of collateral First Mortgage Bonds securing that series of senior notes or tax-exempt bonds effectively represents a single financial obligation, the senior notes and the tax-exempt bonds are not separately shown on the table.
(b)	Represents a series of First Mortgage Bonds issued by the indicated company as collateral for an outstanding series of senior notes that will, at such time as there are no First Mortgage Bonds of the issuing company outstanding (other than collateral First Mortgage Bonds securing payment of senior notes), cease to secure the corresponding series of senior notes and will be cancelled.
NOTE:    Schedule is continued on next page.
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			At December 31,
Interest Rate	Maturity		2006		2005
			(Millions of dollars)
Medium-Term Notes (unsecured)
Pepco:
7.64%	2007	$	35.0	$	35.0
6.25%	2009		50.0		50.0
DPL:
6.75%	2006		-		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:
7.52%	2007		15.0		15.0
Total Medium-Term Notes (unsecured)		$	201.5	$	221.5
Recourse Debt
PCI:
6.59% - 6.69%	2014	$	11.1	$	11.1
7.62%	2007		34.3		34.3
8.12% (a)	2008		92.0		92.0
Total Recourse Debt		$	137.4	$	137.4
Notes (secured)
Pepco Energy Services:
7.85%	2017	$	9.9	$	9.2
Notes (unsecured)
PHI:
3.75%	2006	$	-	$	300.0
5.50%	2007		500.0		500.0
Variable	2010		250.0		250.0
4.00%	2010		200.0		200.0
6.45%	2012		750.0		750.0
5.90%	2016		200.0		-
7.45%	2032		250.0		250.0
Pepco:
Variable	2006		-		50.0
DPL:
5.00%	2014		100.0		100.0
5.00%	2015		100.0		100.0
5.22%	2016		100.0		-
Total Notes (unsecured)		$	2,450.0	$	2,500.0
(a) Debt issued at a fixed rate of 8.24%. The debt was swapped into variable rate debt at the time of issuance.
NOTE:    Schedule is continued on next page. 187 ____________________________________________________________________________________

			At December 31,
Interest Rate	Maturity		2006		2005
			(Millions of dollars)
Nonrecourse debt
PCI:
6.60%	2018	$	-	$	15.9
Acquisition fair value adjustment			-		.1
Total Long-Term Debt		$	4,598.7	$	4,646.9
Net unamortized discount			(4.9)		(5.9)
Current maturities of long-term debt			(825.2)		(438.1)
Total Net Long-Term Debt		$	3,768.6	$	4,202.9
Transition Bonds Issued by ACE Funding
2.89%	2010	$	34.5	$	55.2
2.89%	2011		23.0		31.3
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
Total		$	494.5	$	523.5
Net unamortized discount			(.2)		(.2)
Current maturities of long-term debt			(29.9)		(29.0)
Total Transition Bonds issued by ACE Funding		$	464.4	$	494.3

     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.

     ACE Funding was established in 2001 solely for the purpose of securitizing authorized portions of ACE's recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable transition bond charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). 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. Theholders ofTransition Bonds haverecourseonlyto the assets ofACE Funding.

     The aggregate amounts of maturities for long-term debt and Transition Bonds outstanding at December 31, 2006, are $855.1 million in 2007, $323.6 million in 2008, $82.2 million in 2009, $531.9 million in 2010, $69.9 million in 2011, and $3,230.4 million thereafter.

     Pepco Energy Services Project Funding represents funding for energy savings contracts performed by Pepco Energy Services. The aggregate amounts of maturities for the Project Funding debt outstanding at December 31, 2006, are $2.4 million in 2007, $2.5 million in 2008, $2.0 million in 2009, $2.0 million in 2010, $1.7 million in 2011, and $15.1 million thereafter, and includes the current portion of Project Funding that was provided in exchange for the sale of the customers' accounts receivable.

     PHI's long-term debt is subject to certain covenants. PHI and its subsidiaries are in compliance with all requirements.

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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, 2006 and 2005 is as follows.

	2006	2005
	(Millions of dollars)
Commercial paper	$195.4	$        -
Variable rate demand bonds	154.2	156.4
Total	$349.6	$156.4

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, $275 million, and $250 million, respectively. The commercial paper programs of PHI, Pepco, DPL and ACE are backed by a $1.2 billion credit facility, which is described under the heading "Credit Facility" below.

     Pepco Holdings, Pepco, DPL and ACE had $36 million, $67.1 million, $91.1 million and $1.2 million of commercial paper outstanding at December 31, 2006, respectively. The weighted average interest rate for Pepco Holdings, Pepco, DPL and ACE commercial paper issued during 2006 was 5.1%, 5.25%, 5.3% and 4.79% respectively. The weighted average maturity for Pepco Holdings, Pepco, DPL and ACE was nine, five, seven and four days respectively for all commercial paper issued during 2006.

Variable Rate Demand Bonds

     Variable Rate Demand Bonds ("VRDB") are subject to repayment on the demand of the holders and for this reason are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. PHI expects that the bonds submitted for purchase will continue to be remarketed successfully due to the credit worthiness of the issuing company and because the remarketing resets the interest rate to the then-current market rate. The issuing company also may utilize one of the fixed rate/fixed term conversion options of the bonds to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDB as a source of long-term financing. The VRDB outstanding in 2006 mature in 2007 to 2009 ($8.3 million), 2014 to 2017 ($48.6 million), 2024 ($33.3 million) and 2028 to 2031 ($64 million). The weighted average interest rate for VRDB was 3.55% during 2006 and 2.61 % during 2005.

Credit Facility

     In April 2006, Pepco Holdings, Pepco, DPL and ACE extended their five-year credit agreement for one additional year from 2010 to 2011. The aggregate borrowing limit under the facility is $1.2 billion and the facility commitment expiration date is May 5, 2011. Pepco Holdings' credit limit under this agreement is $700 million.  The credit limit of each of Pepco,

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

     The credit agreement is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies also are permitted to use the facility to borrow funds for general corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties made by the borrower at the time the credit agreement was entered into also must be true at the time the facility is utilized, and the borrower must be in compliance with specified covenants, including the financial covenant described below. However, a material adverse change in the borrower's business, property, and results of operations or financial condition subsequent to the entry into the credit agreement is not a condition to the availability of credit under the facility. Among the covenants contained in the credit agreement are (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, (ii) a restriction on sales or other dispositions of assets, other than sales and dispositions permitted by the credit agreement, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than liens permitted by the credit agreement. The failure to satisfy any of the covenants or the occurrence of specified events that constitute an event of default could result in the acceleration of the repayment obligations of the borrower. The events of default include (i) the failure of any borrowing company or any of its significant subsidiaries to pay when due, or the acceleration of, certain indebtedness under other borrowing arrangements, (ii) certain bankruptcy events, judgments or decrees against any borrowing company or its significant subsidiaries, and (iii) a change in control (as defined in the credit agreement) of Pepco Holdings or the failure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE. The agreement does not include any ratings triggers. There were no balances outstanding at December 31, 2006 and 2005.

(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 the subsidiaries included in its consolidated group pursuant to a written tax sharing agreement that was approved by the SEC in connection with the establishment of PHI as a holding company 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.

     The provision for consolidated income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred tax liabilities (assets) are shown below.

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Provision for Consolidated Income Taxes

	For the Year Ended December 31,
	2006	2005	2004
Operations	(Millions of dollars)
Current Tax (Benefit) Expense
Federal	$ (77.5)	$236.2	$(33.2)
State and local	-	81.9	(9.0)
Total Current Tax (Benefit) Expense	(77.5)	318.1	(42.2)
Deferred Tax Expense (Benefit)
Federal	202.8	(24.4)	185.1
State and local	40.8	(33.4)	32.4
Investment tax credits	(4.7)	(5.1)	(8.0)
Total Deferred Tax Expense (Benefit)	238.9	(62.9)	209.5
Total Income Tax Expense from Operations	$161.4	$255.2	$167.3
Extraordinary Item
Deferred Tax Expense
Federal	-	4.8	-
State and local	-	1.4	-
Total Deferred Tax on Extraordinary Item	-	6.2	-
Total Consolidated Income Tax Expense	$161.4	$261.4	$167.3

Reconciliation of Consolidated Income Tax Expense

		For the Year Ended December 31,
		2006			2005					2004
		Amount	Rate		Amount		Rate			Amount		Rate
	(Millions of dollars)
Income Before Income Taxes and   Extraordinary Item	$	409.7		$	617.4				$	427.9
Preferred Dividends		1.2			2.5					2.8
Income Before Preferred Dividends,   Income Taxes and Extraordinary Item	$	410.9		$	619.9				$	430.7
Income tax at federal statutory rate	$	143.8	.35	$	217.1		.35		$	150.7		.35
Increases (decreases) resulting from
Depreciation		8.1	.02		7.8		.01			9.4		.02
Asset removal costs		(3.2)	(.01)		(3.3	)	(.01	)		(1.7	)	-
State income taxes, net of federal effect		25.6	.06		30.8		.05			27.4		.06
Software amortization		3.0	.01		5.2		.01			(3.6	)	(.01	)
Tax credits		(4.7)	(.01)		(4.7	)	(.01	)		(5.9	)	(.01	)
Cumulative effect of local        tax consolidation		-	-		-		-			(13.2	)	(.03	)
IRS settlement		(.1)	-		-		-			19.7		.05
Company dividends reinvested       in 401(k) plan		(2.1)	(.01)		(2.1	)	-			(2.1	)	(.01	)
Leveraged leases		(9.3)	(.02)		(7.8	)	(.01	)		(8.2	)	(.02	)
Change in estimates related to        prior year tax liabilities		2.6	.01		17.9		.03			(1.0	)	-
Other, net		(2.3)	(.01)		(5.7	)	(.01	)		(4.2	)	(.01	)
Total Consolidated Income Tax Expense	$	161.4	.39	$	255.2		.41		$	167.3		.39

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Components of Consolidated Deferred Tax Liabilities (Assets)

	At December 31,
			2006			2005
	(Millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other book to tax basis differences		$	1,774.6		$	1,630.8
Deferred taxes on amounts to be collected through future rates			43.0			49.5
Deferred investment tax credit			(23.4	)		(25.7	)
Contributions in aid of construction			(60.5	)		(57.9	)
Goodwill, accumulated other comprehensive income,     and valuation adjustments			(187.1	)		(116.8	)
Deferred electric service and electric restructuring liabilities			(58.6	)		(21.7	)
Finance and operating leases			607.6			516.9
Contracts with NUGs			72.6			77.3
Capital loss carryforward			(.4	)		(1.2	)
Federal net operating loss			(.3	)		(64.7	)
Federal Alternative Minimum Tax credit			(5.2	)		(6.9	)
State net operating loss			(45.5	)		(54.0	)
Valuation allowance (State NOLs)			29.5			30.0
Other postretirement benefits			(51.8	)		(43.4	)
Unrealized losses on fair value declines			(1.7	)		(13.3	)
Property taxes, contributions to pension plan, and other			(33.2	)		(51.1	)
Total Deferred Tax Liabilities, Net			2,059.6			1,847.8
Deferred tax assets included in Other Current Assets			24.4			87.2
Total Consolidated Deferred Tax Liabilities, Net Non-Current		$	2,084.0		$	1,935.0

     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 carrybacks from subsequent years.

Resolution of Certain Internal Revenue Service Audit Matters

     In 2006, PHI resolved certain, but not all, tax matters that were raised in Internal Revenue Service audits related to the 2001 and 2002 tax years. Adjustments recorded related to these resolved tax matters resulted in a $6.3 million increase in net income ($2.5 million for Power Delivery and $5.4 million for Other Non-Regulated, partially offset by an unfavorable $1.6 million impact in Corp. & Other). To the extent that the matters resolved related to tax contingencies from the Conectiv heritage companies that existed at the August 2002 merger date, in accordance with accounting rules, an additional adjustment of $9.1 million ($3.1 million related to Power Delivery and $6.0 million related to Other Non-Regulated) was recorded in

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Corp. & Other to eliminate the tax benefits recorded by Power Delivery and Other Non-Regulated against the goodwill balance that resulted from the merger. Also during 2006, the total favorable impact of $2.6 million was recorded that resulted from changes in estimates related to prior year tax liabilities subject to audit ($4.1 million for Power Delivery, partially offset by an unfavorable $1.5 million for Corp. & Other).

     Non Financial Lease Asset

     The IRS, as part of its normal audit of PCI's income tax returns, has questioned whether PCI is entitled to certain ongoing tax deductions being taken by PCI as a result of the adoption by PCI of a carry-over tax basis for a non-lease financial asset acquired in 1998 by a subsidiary of PCI. On December 14, 2004, PCI and the IRS agreed to a Notice of Proposed Adjustment settling this and certain other tax matters. This settlement resulted in a cash outlay in February 2006 for additional taxes and interest of approximately $22.8 million associated with the examination of PCI's 2001-2002 tax returns and an anticipated refund of taxes and interest of approximately $7.1 million when the examination of PCI's 2003 return is completed. In addition, in the fourth quarter of 2004, PCI took a tax charge to earnings of approximately $19.7 million for financial reporting purposes related to this matter. The charge consisted of approximately $16.3 million to reflect the reversal of tax benefits recognized by PCI prior to September 30, 2004, and approximately $3.4 million of interest on the additional taxes. During 2006 and 2005, PCI recorded tax charges to earnings of approximately $.1 million and $.9 million, respectively, for interest on the additional taxes.

Taxes Other Than Income Taxes

     Taxes other than income taxes for each year are shown below. The total amounts below include $332.9 million, $333.4 million, and $305.0 million for the years ended December 31, 2006, 2005, and 2004, respectively, related to the Power Delivery Business, which are recoverable through rates.

	2006	2005	2004
	(Millions of dollars)
Gross Receipts/Delivery	$149.1	$148.3	$138.1
Property	62.7	60.4	60.1
County Fuel and Energy	84.3	89.0	70.6
Environmental, Use and Other	46.9	44.5	42.6
Total	$343.0	$342.2	$311.4

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(9)  MINORITY INTEREST

     The outstanding preferred stock issued by subsidiaries of PHI as of December 31, 2006 and 2005 consisted of the following. The shares of each of these series are redeemable solely at the option of the issuer.

Serial Preferred Stock		Redemption   Price	Shares Outstanding  2006       2005		December 31,    2006       2005
						(Millions of dollars)
Pepco (1)
	$2.44 Series of 1957	$51.00	-	216,846		$	-	$	10.9
	$2.46 Series of 1958	$51.00	-	99,789			-		5.0
	$2.28 Series of 1965	$51.00	-	112,709			-		5.6
						$	-	$	21.5
DPL (2)
	4.0% Series of 1943, $100 per share par value	$105.00	19,809	19,809		$	2.0	$	2.0
	3.7% Series of 1947, $100 per share par value	$104.00	39,866	39,866			4.0		4.0
	4.28% Series of 1949, $100 per share par value	$104.00	28,460	28,460			2.8		2.8
	4.56% Series of 1952, $100 per share par value	$105.00	19,571	19,571			2.0		2.0
	4.20% Series of 1955, $100 per share par value	$103.00	25,404	25,404			2.5		2.5
	5.0% Series of 1956, $100 per share par value	$104.00	48,588	48,588			4.9		4.9
						$	18.2	$	18.2
ACE
	4.0% Series of 1944, $100 per share par value	$105.50	24,268	24,268		$	2.4	$	2.4
	4.35% Series of 1949, $100 per share par value	$101.00	2,942	2,942			.3		.3
	4.35% Series of 1953, $100 per share par value	$101.00	1,680	1,680			.2		.2
	4.10% Series of 1954, $100 per share par value	$101.00	20,504	20,504			2.0		2.0
	4.75% Series of 1958, $100 per share par value	$101.00	8,631	8,631			.9		.9
	5.0% Series of 1960, $100 per share par value	$100.00	4,120	4,120			.4		.4
						$	6.2	$	6.2
	Total Preferred Stock of Subsidiaries					$	24.4	$	45.9

(1)

In October 2005, Pepco redeemed the following shares of preferred stock: (i) 74,103 shares of $2.46 Series of 1958, (ii) 13,148 shares of $2.28 Series of 1965, and 22,795 shares of $2.44 Series of 1957, for an aggregate redemption amount of $3.7 million, $.7 million and $1.1 million, respectively. On March 1, 2006, Pepco redeemed the remaining outstanding shares of each series of its preferred stock, at 102% of par, for an aggregate redemption amount of $21.9 million.

(2)

On January 18, 2007, DPL redeemed all of the outstanding shares of its preferred stock, at prices ranging from 103% to 105% of par, in an aggregate amount of approximately $18.9 million.

(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 (LTIP), the objective of which is to increase shareholder value by providing a long-term incentive to reward officers, key employees, and directors of Pepco Holdings and its subsidiaries and to increase the ownership of Pepco Holdings' common stock by such individuals. Any officer or key employee of Pepco Holdings or its subsidiaries may be designated by 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.

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     Total stock-based compensation expense recorded in the Consolidated Statements of Earnings for the years ended December 31, 2006, 2005, and 2004 is $5.8 million, $4.4 million, and $4.3 million, respectively. For the years ended December 31, 2006, 2005, and 2004, $.1 million, zero, and zero, respectively, in tax benefits was recognized in relation to stock-based compensation costs of stock awards. No compensation costs related to restricted stock grants were capitalized for the years ended December 31, 2006, 2005 and 2004.

     PHI recognizes compensation expense related to Performance Restricted Stock Awards based on the fair value of the awards at date of grant. PHI estimates the fair value of market condition awards using a Monte Carlo simulation model, in a risk-neutral framework, based on the following assumptions:

	Performance Period
	2004-2006	2005-2007
Risk-free interest rate (%)	2.11	3.37
Peer volatilities (%)	16.3 - 62.5	15.5 - 60.1
Peer correlations	0.13 - 0.69	0.15 - 0.72
Fair value of restricted share	$24.06	$26.92

     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 received in exchange for the Conecti v options are exercisable.

     At the time of the acquisition of Conectiv by Pepco, 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, May 2000, January 2001, May 2001, January 2002, and May 2002 are exercisable.

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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.

	2006			2005			2004
	Number of Options		Weighted AveragePrice	Number of Options		Weighted AveragePrice	Number of Options		Weighted   Average   Price
Beginning-of-year balance	1,864,250	$	22.1944	2,063,754	$	21.8841	2,115,037	$	21.8131
Options exercised	733,526	$	21.7081	196,299	$	18.9834	41,668	$	18.9385
Options forfeited	-	$	-	3,205	$	19.0300	9,615	$	19.0300
End-of-year balance	1,130,724	$	22.5099	1,864,250	$	22.1944	2,063,754	$	21.8841
Exercisable at end of year	1,130,724	$	22.5099	1,814,350	$	22.1840	1,739,032	$	21.9944

     All stock options have an expiration date of ten years from the date of grant.

     The aggregate intrinsic value of stock options outstanding and exercisable at December 31, 2006, 2005, and 2004 was $4.1 million, $.1 million, and $(1.1) million, respectively.

     The total intrinsic value of stock options exercised during the years ended December 31, 2006, 2005, and 2004 was $2.2 million, $.8 million, and $.1 million, respectively. For the years ended December 31, 2006, 2005, and 2004, $.9 million, $.3 million, and zero, respectively, in tax benefits was recognized in relation to stock-based compensation costs of stock options.

     As of December 31, 2006, an analysis of options outstanding by exercise prices is as follows:

Range of Exercise Prices	Number Outstanding and Exercisable at December 31, 2006	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life (in Years)
$13.08 to $19.30	326,083	$18.7373	5.4
$21.83 to $29.78	804,641	$24.0387	3.3
$13.08 to $29.78	1,130,724	$22.5099	3.9

     Prior to the adoption of SFAS No. 123R on January 1, 2006, Pepco Holdings recognized 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 2006, 2005 and 2004 with respect to stock options granted under the LTIP.

     There were no options granted in 2006, 2005, or 2004.

     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 2006, 2005 and 2004 under Pepco Holdings' Performance Restricted Stock Program for performance periods 2007-2009, 2006-2008 and 2005-2007 were 190,657, 218,108 and 247,400, respectively. Additionally, beginning in 2006, time-restricted share award opportunities with a requisite service period of three years were established under the LTIP. The target number of share award opportunities for these awards was 95,314 for the 2007-2009 time period and 109,057 for the 2006-2008 time period. The fair

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value per share on award date for the performance restricted stock was $25.54 for the 2007-2009 award, $23.28 for the 2006-2008 award, and $26.92 for the 2005-2007 award. Depending on the extent to which the performance criteria are satisfied, the executives are eligible to earn shares of common stock and dividends accrued thereon over the vesting period, under the Performance Restricted Stock Program ranging from 0% to 200% of the target share award opportunities, inclusive of dividends accrued. There were 418,426 awards earned with respect to the 2004-2006 share award opportunity.

     The maximum number of share award opportunities granted under the Merger Integration Success Program 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% vested 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 were 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 cost reduction goals were maintained and Pepco Holdings' financial performa nce were satisfactory. A total of 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. A total of 44,644 shares, including reinvested dividends, vested on March 7, 2006, for the original performance period ended December 31, 2003, that was extended to December 31, 2005.

     Under the LTIP, non-employee directors are entitled to a grant on May 1 of each year of a nonqualified 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 acquisition of Conectiv by Pepco, 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. As of December 31, 2006, 95,513 converted shares have vested and 7,823 shares remain unvested.

     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 vested on June 1, 2006.

     The 2006 activity for non-vested share opportunities is summarized below. The information presented in the table is for Pepco Holdings, including Conectiv PARS converted to Pepco Holdings restricted stock.

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	Number of Shares			Weighted Average GrantDate Fair Value
Non-vested share opportunities at January 1, 2006		832,813			$	22.933
Granted		327,165			$	23.280
Reinvested dividends		7,560			$	19.735
Vested		(104,593	)		$	(19.515	)
Forfeiture due to non-performance		(303,357	)		$	(20.201	)
Forfeited		(30,819	)		$	(25.169	)
Non-vested share opportunities at December 31, 2006		728,769			$	24.588

     The total fair value of restricted stock awards vested during the years ended December 31, 2006, 2005, and 2004 was $2.0 million, $2.7 million, and $1.0 million, respectively.

     As of December 31, 2006, there was approximately $3.8 million of unrecognized compensation cost (net of estimated forfeitures) related to non-vested stock granted under the plans. That cost is expected to be recognized over a weighted-average period of 2 years.

     For the years ended December 31, 2006, 2005, and 2004, Pepco Holdings recorded dividends from its subsidiaries as follows:

Subsidiary		2006		2005		2004
		(Millions of dollars)
Pepco	$	99.0	$	62.9	$	102.4
DPL		15.0		36.4		68.0
ACE		109.0		95.9		10.6
Conectiv Energy		-		50.0		-
	$	223.0	$	245.2	$	181.0

Dividend Restrictions

     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) the prior rights of holders of existing and future 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 (iii) certain provisions of ACE's charter which imposes restrictions on payment of common stock dividends for the benefit of preferred stockholders. Restricted net asset s related to PHI's consolidated subsidiaries amounted to approximately $1.9 billion at December 31, 2006 and 2005. PHI had no restricted retained earnings or restricted net income at December 31, 2006 and 2005.

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Directors' Deferred Compensation

     Under the Pepco Holdings' Executive and Director Deferred Compensation Plan, Pepco Holdings directors may elect to defer all or part of their retainer or meeting fees that constitute normal compensation. Deferred retainer or meeting fees can be invested in phantom Pepco Holdings shares and earn dividends as well as appreciation equal to the amount of increase in fair value of the phantom shares. The ultimate payout is in cash. The amount deferred and invested in phantom Pepco Holdings shares in the years ended December 31, 2006, 2005 and 2004 was $.1 million, $.1 million and $.3 million, respectively.

     Compensation recognized in respect of dividends and increase in fair value in the years ended December 31, 2006, 2005 and 2004 was $.3 million, $.1 million and $.2 million, respectively. The balance of deferred compensation invested in phantom Pepco Holdings' shares at December 31, 2006 and 2005 was $1.8 million and $1.4 million.

Calculations of Earnings Per Share of Common Stock

     Reconciliations of the numerator and denominator for basic and diluted earnings per share of common stock calculations are shown below.

		For the Year Ended December 31,
			2006		2005		2004
			(Millions of dollars, except share data)
Income (Numerator):
Net Income		$	248.3	$	371.2	$	260.6
Add:    (Loss) gain on redemption of subsidiary's             preferred stock			(.8)		(.1)		.5
Earnings Applicable to Common Stock		$	247.5	$	371.1	$	261.1
Shares (Denominator) (a):
Weighted average shares outstanding for basic computation:
Average shares outstanding			190.7		189.0		176.8
Adjustment to shares outstanding			(.1)		(.1)		-
Weighted Average Shares Outstanding for Computation of   Basic Earnings Per Share of Common Stock			190.6		188.9		176.8
Weighted average shares outstanding for diluted computation:
Average shares outstanding			190.7		189.0		176.8
Adjustment to shares outstanding			.4		.2		-
Weighted Average Shares Outstanding for Computation of   Diluted Earnings Per Share of Common Stock			191.1		189.2		176.8
Basic earnings per share of common stock		$	1.30	$	1.96	$	1.48
Diluted earnings per share of common stock		$	1.30	$	1.96	$	1.48
(a)	The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS as they are considered to be anti-dilutive were approximately .6 million for the year ended December 31, 2006 and 1.4 million for the years ended December 31, 2005 and 2004.

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     PHI maintains a Shareholder Dividend Reinvestment Plan (DRP) through which shareholders may reinvest cash dividends and both existing shareholders and new investors can make purchases of shares of PHI common stock through the investment of not less than $25 each calendar month nor more than $200,000 each calendar year. Shares of common stock purchased through the DRP may be original issue shares or, at the election of PHI, shares purchased in the open market. There were 1,232,569, 1,228,505, and 1,471,936 original issue shares sold under the DRP in 2006, 2005 and 2004, respectively.

     The following table presents Pepco Holdings' common stock reserved and unissued at December 31, 2006:

Name of Plan	Number of   Shares
DRP	3,713,555
Conectiv Incentive Compensation Plan (a)	1,396,836
Potomac Electric Power Company Long-Term Incentive Plan (a)	838,700
Pepco Holdings, Inc. Long-Term Incentive Plan	9,626,494
Pepco Holdings, Inc. Non-Management Directors Compensation Plan	496,858
Pepco Holdings, Inc. Savings Plan (b)	5,045,000
Total	21,117,443

(a)

No further awards will be made under this plan.

(b)

Effective January 30, 2006, Pepco Holdings established the Pepco Holdings, Inc. Retirement Savings Plan which is an amalgam of, and a successor to, (i) the Potomac Electric Power Company Savings Plan for Bargaining Unit Employees, (ii) the Potomac Electric Power Company Retirement Savings Plan for Management Employees (which resulted from the merger, effective January 1, 2005, of the Potomac Electric Power Company Savings Plan for Non-Bargaining Unit, Non-Exempt Employees and the Potomac Electric Power Company Savings Plan for Exempt Employees), (iii) the Conectiv Savings and Investment Plan, and (iv) the Atlantic City Electric 401(k) Savings and Investment Plan - B.

(11)  FAIR VALUES OF FINANCIAL INSTRUMENTS

     The estimated fair values of Pepco Holdings' financial instruments at December 31, 2006 and 2005 are shown below.

		At December 31,
		2006				2005
		(Millions of dollars)
		Carrying  Amount		Fair Value		Carrying  Amount		Fair Value
Assets
Derivative Instruments	$	109.1	$	109.1	$	260.0	$	260.0
Liabilities and Capitalization
Long-Term Debt	$	3,768.6	$	3,807.3	$	4,202.9	$	4,308.0
Transition Bonds issued by ACE Funding	$	464.4	$	462.3	$	494.3	$	496.7
Derivative Instruments	$	186.8	$	186.8	$	201.3	$	201.3
Long-Term Project Funding	$	23.3	$	23.3	$	25.5	$	25.5
Serial Preferred Stock	$	-	$	-	$	21.5	$	18.2
Redeemable Serial Preferred Stock	$	24.4	$	21.7	$	24.4	$	17.2

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     The methods and assumptions described below were used to estimate, at December 31, 2006 and 2005, the fair value of each class of financial instruments shown above for which it is practicable to estimate a value.

     The fair values of derivative instruments were derived based on quoted market prices.

     Long-Term Debt includes recourse and non-recourse debt issued by PCI. The fair values of this PCI debt, excluding amounts due within one year, were based on current rates offered to similar companies for debt with similar remaining maturities. The fair values of all other Long-Term Debt and Transition Bonds issued 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 Serial Preferred Stock 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 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 generating assets to Mirant (formerly Southern Energy, Inc.). In July 2003, Mirant 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). On December 9, 2005, the Bankruptcy Court approved the Plan of Reorganization (the Reorganization Plan) of Mirant and the Mirant business emerged from bankruptcy on January 3, 2006, as a new corporation of the same name (for purposes of this section, together with its predecessors, Mirant).

     As part of the bankruptcy proceeding, Mirant had been seeking to reject certain ongoing contractual arrangements under the Asset Purchase and Sale Agreement entered into by Pepco and Mirant for the sale of the generating assets that are described below. The Reorganization Plan did not resolve the issues relating to Mirant's efforts to reject these obligations nor did it resolve certain Pepco damage claims against the Mirant bankruptcy estate.

     Power Purchase Agreement

     The Panda PPA obligates Pepco to purchase from Panda 230 megawatts of energy and capacity annually through 2021. At the time of the sale of Pepco's generating assets to Mirant, the purchase price of the energy and capacity under the Panda PPA was, and since that time has continued to be, substantially in excess of the 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 through 2021 to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the Panda PPA at a price equal to Pepco's purchase price from Panda (the PPA-Related Obligations).

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     The SMECO Agreement

     Under the Asset Purchase and Sale Agreement, Pepco assigned to Mirant a Facility and Capacity Agreement entered into by Pepco with Southern Maryland Electric Cooperative, Inc. (SMECO), under which Pepco was obligated to purchase from SMECO the capacity of an 84-megawatt combustion turbine installed and owned by SMECO at a former Pepco generating facility at a cost of approximately $500,000 per month until 2015 (the SMECO Agreement). Pepco is responsible to SMECO for the performance of the SMECO Agreement if Mirant fails to perform its obligations thereunder.

     Settlement Agreements with Mirant

     On May 30, 2006, Pepco, PHI, and certain affiliated companies entered into a Settlement Agreement and Release (the Settlement Agreement) with Mirant, which, subject to court approval, settles all outstanding issues between the parties arising from or related to the Mirant bankruptcy. Under the terms of the Settlement Agreement:

· Mirant will assume the Asset Purchase and Sale Agreement, except for the PPA-Related Obligations, which Mirant will be permitted to reject.

· Pepco will receive an allowed claim under the Reorganization Plan in an amount that will result in a total aggregate distribution to Pepco, net of certain transaction expenses, of $520 million, consisting of (i) $450 million in damages resulting from the rejection of the PPA-Related Obligations and (ii) $70 million in settlement of other Pepco damage claims against the Mirant bankruptcy estate (the Pepco Distribution).

· Except as described below, the $520 million Pepco Distribution will be effected by means of the issuance to Pepco of shares of Mirant common stock (consisting of an initial distribution of 13.5 million shares of Mirant common stock, followed thereafter by a number of shares of Mirant common stock to be determined), which Pepco will be obligated to resell promptly in one or more block sale transactions. If the net proceeds that Pepco receives from the resale of the shares of Mirant common stock are less than $520 million, Pepco will receive a cash payment from Mirant equal to the difference, and if the net proceeds that Pepco receives from the resale of the shares of Mirant common stock are more than $520 million, Pepco will make a cash payment to Mirant equal to the difference.

· If the closing price of shares of Mirant common stock is less than $16.00 per share for four business days in a twenty consecutive business day period, and Mirant has not made a distribution of shares of Mirant common stock to Pepco under the Settlement Agreement, Mirant has the one-time option to elect to assume, rather than reject, the PPA-Related Obligations. If Mirant elects to assume the PPA-Related Obligations, the Pepco Distribution will be reduced to $70 million.

· All pending appeals, adversary actions or other contested matters between Pepco and Mirant will be dismissed with prejudice, and each will release the other from any and all claims relating to the Mirant bankruptcy.

     Separately, Mirant and SMECO have entered into a Settlement Agreement and Release (the SMECO Settlement Agreement). The SMECO Settlement Agreement provides that Mirant will assume, rather than reject, the SMECO Agreement. This assumption ensures that Pepco will not

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incur liability to SMECO as the guarantor of the SMECO Agreement due to the rejection of the SMECO Agreement, although Pepco will continue to guarantee to SMECO the future performance of Mirant under the SMECO Agreement.

     According to their terms, the Settlement Agreement and the SMECO Settlement Agreement will become effective when the Bankruptcy Court or the United States District Court for the Northern District of Texas (the District Court), as applicable, has entered a final order, not subject to appeal or rehearing, approving both the Settlement Agreement and the SMECO Settlement Agreement.

     On August 9, 2006, the Bankruptcy Court issued an order approving the Settlement Agreement and the SMECO Settlement Agreement. On August 18, 2006, certain holders of Mirant bankruptcy claims, who had objected to approval of the Settlement Agreement and the SMECO Settlement Agreement before the Bankruptcy Court, appealed the approval order to the District Court. On December 26, 2006, the District Court issued an order affirming the Bankruptcy Court's order approving the Settlement Agreement. On January 25, 2007, the parties that previously appealed the Bankruptcy Court's order filed a notice of appeal of the District Court's order with the United States Court of Appeals for the Fifth Circuit (the Fifth Circuit). On February 12, 2007, the Fifth Circuit issued a briefing schedule. The brief of the appealing creditors is due on March 26, 2007, while Mirant's and Pepco's briefs are due on April 30, 2007.

     In August 2006, Mirant made a cash payment to Pepco of $70 million, which became due in accordance with the terms of the Settlement Agreement as a result of the approval of the Settlement Agreement by the Bankruptcy Court. If the Bankruptcy Court order approving the Settlement Agreement becomes a final order after the exhaustion of all appeals, the payment will be taken into account as if it were proceeds from the resale by Pepco of shares of the Mirant common stock, as described above, and treated as a portion of the $520 million payment due Pepco. If the Bankruptcy Court approval of the Settlement Agreement is not upheld on appeal, Pepco must repay this cash payment to Mirant. Therefore, no income statement impact has been recognized in relation to the $70 million payment.

     Until the approval of the Settlement Agreement and the SMECO Settlement Agreement becomes final, Mirant is required to continue to perform all of its contractual obligations to Pepco and SMECO. Pepco intends to use the $450 million portion of the Pepco Distribution related to the rejection of the PPA-Related Obligations to pay for future capacity and energy purchases under the Panda PPA.

     In litigation prior to the entry into the Settlement Agreement, the District Court had entered orders denying Mirant's attempt to reject the PPA-Related Obligations and directing Mirant to resume making payments to Pepco pursuant to the PPA-Related Obligations, which Mirant had suspended. Mirant is making the payments as required by the District Court order. On July 19, 2006, the Fifth Circuit issued an opinion affirming the District Court's orders. On September 4, 2006, Mirant filed a petition for rehearing and motion to stay the appeals pending completion of the settlement between the parties. On September 12, 2006, the Fifth Circuit issued an Order denying Mirant's motion for stay. On September 21, 2006, the Fifth Circuit issued an Order summarily denying Mirant's petition for rehearing. The appeal period has expired and that order is now final and nonappealable.

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Rate Proceedings

     PHI's regulated utility subsidiaries currently have four active distribution base rate cases underway. Pepco has filed electric distribution base rate cases in the District of Columbia and Maryland; DPL has filed a gas distribution base rate case in Delaware (which is the subject of a settlement agreement as discussed below) and an electric base rate case in Maryland. In each of these cases, the utility has proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers. The BSA will increase rates if revenues from distribution deliveries fall below the level approved by the applicable regulatory commission and will decrease rates if revenues from distribution deliveries are above the commission-approved level. The end result will be that the utility will collect its authorized revenues for distribution deliveries. As a consequence, a BSA "decouples" revenue from unit sales consumption and ties the growth in revenues to the growth in the num ber of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable utility distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers' delivery bills, and (iv) removes any disincentives for the regulated utilities to promote energy efficiency programs for their customers, because it breaks the link between overall sales volumes and delivery revenues. DPL has proposed a monthly BSA in the gas base rate case and, in each of the electric base rate cases, the companies have proposed a quarterly BSA.

     Delaware

     On August 31, 2006, DPL submitted its 2006 Gas Cost Rate (GCR) filing to the DPSC, which permits DPL to recover gas procurement costs through customer rates. The proposed decrease of approximately 9.6% is in anticipation of decreasing natural gas commodity costs. On October 3, 2006, the DPSC issued its initial order approving the proposed rates, which became effective November 1, 2006, subject to refund pending final DPSC approval after evidentiary hearings. Any amounts subject to refund would be deferred, resulting in no earnings impact.

     On February 23, 2007, DPL submitted an additional filing to the DPSC that proposed a 4.3% decrease in the GCR effective April 1, 2007, in compliance with its gas service tariff and to ensure collections are more aligned with expenses. DPL expects DPSC approval of the rate decrease in late March 2007, subject to refund pending final DPSC approval after evidentiary hearings.

     On August 31, 2006, DPL submitted an application to the DPSC for an increase in gas distribution base rates, including a proposed BSA. The application requested an annual increase of approximately $15 million or an overall increase of 6.6%, including certain miscellaneous tariff fees, reflecting a proposed return on equity (ROE) of 11.00%. If the BSA is not approved, the proposed annual increase would be $15.5 million or an overall increase of 6.8%, reflecting an ROE of 11.25%. On October 17, 2006, the DPSC authorized DPL to place into effect beginning November 1, 2006, subject to refund, gas base rates designed to produce an annual interim increase in revenue of approximately $2.5 million. On February 16, 2007, all of the parties in this proceeding (DPL, DPSC staff and the Delaware Division of Public Advocate) filed a settlement agreement with the DPSC. The settlement provisions include a $9.0 million increase in distribution rates, including certain miscellaneous tarif f fees (of which $2.5 million was put into effect on November 1, 2006, as noted above), an ROE of 10.25%, and a change in depreciation rates that result in a $2.1 million reduction in pre-tax annual depreciation expense. Although the settlement agreement does not include a BSA, it provides for all of the parties to

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the case to participate in any generic statewide proceeding for the purpose of investigating BSA mechanisms for electric and gas distribution utilities. In a separate proceeding, DPL has requested that a docket be opened for this purpose. Under the settlement agreement, rates will become effective on April 1, 2007. A DPSC decision is expected by the end of March 2007.

     District of Columbia

     In February 2006, Pepco filed an update to the District of Columbia GPC for the periods February 8, 2002 through February 7, 2004 and February 8, 2004 through February 7, 2005. The GPC provides for sharing of the profit from SOS sales. The update to the GPC in the District of Columbia takes into account the $112.4 million in proceeds received by Pepco from the December 2005 sale of an allowed bankruptcy claim against Mirant arising from a settlement agreement entered into with Mirant relating to Mirant's obligation to supply energy and capacity to fulfill Pepco's SOS obligations in the District of Columbia. The filing also incorporates true-ups to previous disbursements in the GPC for the District of Columbia. In the filing, Pepco requested that $24.3 million be credited to District of Columbia customers during the twelve-month period beginning April 2006. On June 15, 2006, the DCPSC granted conditional approval of the GPC update as filed, effective July 1, 2006. Final approval by the DCPSC is pending.

     On December 12, 2006, Pepco submitted an application to the DCPSC to increase electric distribution base rates, including a proposed BSA. The application requested an annual increase of approximately $46.2 million or an overall increase of 13.5%, reflecting a proposed ROE of 10.75%. If the BSA is not approved, the proposed annual increase would be $50.5 million or an overall increase of 14.8%, reflecting an ROE of 11.00%. The application also proposed a Pension/OPEB Expense Surcharge that will allow Pepco to reflect in its distribution rates the increases and decreases that occur in the level of its pension and other post-employment benefits expense. A DCPSC decision is expected in mid-September 2007.

     Maryland

     On November 17, 2006, DPL and Pepco each submitted an application to the MPSC to increase electric distribution base rates, including a proposed BSA. The applications requested an annual increase for DPL of approximately $18.4 million or an overall increase of 3.2%, including certain miscellaneous tariff fees, and an annual increase for Pepco of approximately $47.4 million or an overall increase of 10.9%, reflecting a proposed ROE for each of 11.00%. If the BSA is not approved, the proposed annual increase for DPL would be $20.3 million or an overall increase of 3.6%, and for Pepco would be $55.7 million or an overall increase of 12.9%, reflecting a proposed ROE for each of 11.25%. Each of the applications also proposed a Pension/OPEB Expense Surcharge that would allow the utility to reflect in its distribution rates the increases and decreases that occur in the level of its pension and other post-employment benefits expense. The applications requested that rates go into effect on December 17, 2006. In an order dated December 11, 2006, the MPSC suspended the proposed rates pending MPSC approval. MPSC decisions are expected in June 2007.

     Federal Energy Regulatory Commission

     On May 15, 2006, Pepco, ACE and DPL updated their FERC-approved formula transmission rates based on the FERC Form 1 data for 2005 for each of the utilities. These rates became effective on June 1, 2006, as follows: for Pepco, $12,009 per megawatt per year; for ACE, $14,155 per megawatt per year; and for DPL, $10,034 per megawatt per year. By operation of

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the formula rate process, the new rates incorporate true-ups from the 2005 formula rates that were effective June 1, 2005 and the new 2005 customer demand or peak load. Also, beginning in January 2007, the new rates will be applied to 2006 customer demand data, replacing the 2005 demand data that is currently used. This demand component is driven by the prior year peak loads experienced in each respective zone. Further, the rate changes will be positively impacted by changes to distribution rates for Pepco and DPL based on the merger settlements in Maryland and the District of Columbia. The net earnings impact expected from the network transmission rate changes is estimated to be a reduction of approximately $5 million year over year (2005 to 2006).

ACE Restructuring Deferral Proceeding

     Pursuant to orders issued by the NJBPU under the New Jersey Electric Discount and Energy Competition Act (EDECA), beginning August 1, 1999, ACE was obligated to provide BGS to retail electricity customers in its service territory who did not choose a competitive energy supplier. For the period August 1, 1999 through July 31, 2003, ACE's aggregate costs that it was allowed to recover from customers 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) related to ACE's Levelized Energy Adjustment Clause and ACE's Demand Side Management Programs. ACE established a regulatory asset in an amount equal to the balance of under-recovered costs.

     In August 2002, ACE filed a petition with the NJBPU for the recovery of approximately $176.4 million in actual and projected deferred costs relating to the provision of BGS and other restructuring related costs incurred by ACE over the four-year period August 1, 1999 through July 31, 2003, 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.

     In July 2004, the NJBPU issued a final order in the restructuring deferral proceeding confirming a July 2003 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 then pending base rate case for further consideration approximately $25.4 million of the deferred balance (the base rate case ended in a settlement approved by the NJBPU in May 2005, the result of which is that any net rate impact from the deferral account recoveries and credits in future years will depend in part on whether rates associated with other deferred accounts considered in the case continue to generate over-collections relative to costs), 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. Although ACE believes the record does not justify the level of disallowance imposed by the NJBPU in the final order, the $44.6 million of disallowed incurred costs were reserved during the years 1999 through 2003 (primarily 2003) through charges to earnings, primarily in the operating expense line item "deferred electric service costs," with a corresponding reduction in the regulatory asset balance sheet account. In August 2004, ACE filed a notice of appeal with respect to the July 2004 final order with the Appellate Division of the Superior Court of New Jersey (the Appellate Division), which hears appeals of the decisions of New Jersey administrative agencies, including the NJBPU. Briefs in the appeal were also filed by the Division of the New Jersey Ratepayer Advocate and by Cogentrix Energy Inc., the co-owner of

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two cogeneration power plants with contracts to sell ACE approximately 397 megawatts of electricity, as cross-appellants between August 2005 and January 2006. The Appellate Division has not yet set the schedule for oral argument.

Divestiture Cases

     District of Columbia

     Final briefs on Pepco's District of Columbia divestiture proceeds sharing application were filed with the DCPSC in July 2002 following an evidentiary hearing in June 2002. That application was filed to implement a provision of Pepco's DCPSC-approved divestiture settlement that provided for a sharing of any net proceeds from the sale of Pepco's generation-related assets. One of the principal issues in the case is whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code (IRC) and its implementing regulations. As of December 31, 2006, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6.5 million and $5.8 million, respectively.

     Pepco believes that a sharing of EDIT and ADITC would violate the IRS normalization rules. Under these rules, Pepco could not transfer the EDIT and the ADITC benefit to customers more quickly than on a straight line basis over the book life of the related assets. Since the assets are no longer owned there is no book life over which the EDIT and ADITC can be returned. If Pepco were required to share EDIT and ADITC and, as a result, the normalization rules were violated, Pepco would be unable to use accelerated depreciation on District of Columbia allocated or assigned property. In addition to sharing with customers the generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS an amount equal to Pepco's District of Columbia jurisdictional generation-related ADITC balance ($5.8 million as of December 31, 2006), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($4.7 million as of December 31, 2006) in ea ch case as those balances exist as of the later of the date a DCPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the DCPSC order becomes operative.

     In March 2003, the IRS issued a notice of proposed rulemaking (NOPR), which would allow for the sharing of EDIT and ADITC related to divested assets with utility customers on a prospective basis and at the election of the taxpayer on a retroactive basis. In December 2005 a revised NOPR was issued which, among other things, withdrew the March 2003 NOPR and eliminated the taxpayer's ability to elect to apply the regulation retroactively. Comments on the revised NOPR were filed in March 2006, and a public hearing was held in April 2006. Pepco filed a letter with the DCPSC in January 2006, in which it has reiterated that the DCPSC should continue to defer any decision on the ADITC and EDIT issues until the IRS issues final regulations or states that its regulations project related to this issue will be terminated without the issuance of any regulations. Other issues in the divestiture proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.

     Pepco believes that its calculation of the District of Columbia customers' share of divestiture proceeds is correct. However, depending on the ultimate outcome of this proceeding, Pepco could be required to make additional gain-sharing payments to District of Columbia customers,

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

     Maryland

    Pepco filed its divestiture proceeds plan application with the MPSC in April 2001. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that has been raised in the District of Columbia case. See the discussion above under "Divestiture Cases -- District of Columbia." As of December 31, 2006, the Maryland allocated portions of EDIT and ADITC associated with the divested generating 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 with respect to the application 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 (discussed abo ve) 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 ($9.1 million as of December 31, 2006), and the Maryland-allocated portion of generation-related ADITC. Furthermore, Pepco would have to pay to the IRS an amount equal to Pepco's Maryland jurisdictional generation-related ADITC balance ($10.4 million as of December 31, 2006), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($8.4 million as of December 31, 2006), in each case as those balances exist 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. The Hearing Examiner decided all other issues in favor of Pepco, except for the determination tha t 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. Pepco filed a letter with the MPSC in January 2006, in which it has reiterated that the MPSC should continue to defer any decision on the ADITC and EDIT issues until the IRS issues final regulations or states that its regulations project related to this issue will be terminated without the issuance of any regulations.

     In December 2003, Pepco appealed the Hearing Examiner's decision to the MPSC as it relates to the treatment of EDIT and ADITC and corporate reorganization costs. The MPSC has not issued any ruling on the appeal and Pepco does not believe that it will do so until action is taken by the IRS as described above. 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 in addition to the additional gain-sharing payments relating to the disallowed severance payments, which Pepco is not contesting. 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

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payments to the IRS, if required, would have a material adverse impact on its financial position or cash flows.

     New Jersey

     In connection with the divestiture by ACE of its nuclear generating assets, the NJBPU in July 2000 preliminarily determined that the amount of stranded costs associated with the divested assets that ACE could recover from ratepayers should be reduced by approximately $94.5 million, representing the amount of the accumulated deferred federal income taxes (ADFIT) associated with the divested nuclear assets. However, due to uncertainty under federal tax law regarding whether the sharing of federal income tax benefits associated with the divested assets, including ADFIT, with ACE's customers would violate the normalization rules, ACE submitted a request to the IRS for a Private Letter Ruling (PLR) to clarify the applicable law. The NJBPU has delayed its final determination of the amount of recoverable stranded costs until after the receipt of the PLR.

     On May 25, 2006, the IRS issued a PLR in which it stated that returning to ratepayers any of the unamortized ADFIT attributable to accelerated depreciation on the divested assets after the sale of the assets by means of a reduction of the amount of recoverable stranded costs would violate the normalization rules.

     On June 9, 2006, ACE submitted a letter to the NJBPU to request that the NJBPU conduct proceedings to finalize the determination of the stranded costs associated with the sale of ACE's nuclear assets in accordance with the PLR. ACE's request remains pending.

Default Electricity Supply Proceedings

     Delaware

     Effective May 1, 2006, SOS replaced fixed-rate POLR service for customers who do not choose an alternative electricity supplier. In October 2005, the DPSC approved DPL as the SOS provider to its Delaware delivery customers. DPL obtains the electricity to fulfill its SOS supply obligation under contracts entered pursuant to a competitive bid procedure approved by the DPSC. The bids received for the May 1, 2006, through May 31, 2007, period have had the effect of increasing rates significantly for all customer classes, including an average residential customer increase of 59%, as compared to the fixed rates previously in effect.

     To address this increase in rates, Delaware in April 2006 enacted legislation that provides for a deferral of the financial impact on customers of the increases through a three-step phase-in of the rate increases, with 15% of the increase taking effect on May 1, 2006, 25% of the increase taking effect on January 1, 2007, and any remaining balance taking effect on June 1, 2007, subject to the right of customers to elect not to participate in the deferral program. Customers who do not "opt-out" of the rate deferral program are required to pay the amounts deferred, without any interest charge, over a 17-month period beginning January 1, 2008. As of December 31, 2006, approximately 53% of the eligible Delaware customers have opted not to participate in the deferral of the SOS rates offered by DPL. With approximately 47% of the eligible customers participating in the phase-in program, DPL anticipates a maximum deferral balance of $51.4 million.

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     Maryland

     Pursuant to orders issued by the MPSC in November 2006, Pepco and DPL each is the SOS provider to its delivery customers who do not choose an alternative electricity supplier. Each companypurchases the power supply required to satisfy its SOS obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved and supervised by the MPSC. In March 2006, Pepco and DPL each announced the results of competitive bids to supply electricity to its Maryland SOS customers for one year beginning June 1, 2006. Due to significant increases in the cost of fuels used to generate electricity, the auction results had the effect of increasing the average monthly electric bill by about 38.5% and 35% for Pepco's and DPL's Maryland residential customers, respectively.

     On April 21, 2006, the MPSC approved a settlement agreement among Pepco, DPL, the staff of the MPSC and the Office of Peoples Counsel of Maryland, which provides for a rate mitigation plan for the residential customers of each company. Under the plan, the full increase for each company's residential customers who affirmatively elect to participate are being phased-in in increments of 15% on June 1, 2006, 15.7% on March 1, 2007 and the remainder on June 1, 2007. Customers electing to participate in the rate deferral plan will be required to pay the deferred amounts over an 18-month period beginning June 1, 2007. Both Pepco and DPL will accrue the interest cost to fund the deferral program. The interest cost will be absorbed by Pepco and DPL during the period that the deferred balance is accumulated and collected from customers, to the extent of and offset against the margins that the companies otherwise would earn for providing SOS to residential customers. As of December 31, 2006, approximately 2% of Pepco's residential customers and approximately 1% of DPL's residential customers had elected to participate in the phase-in program.

     On June 23, 2006, Maryland enacted legislation that extended the period for customers to elect to participate in the phase-in of higher rates and revised the obligation to provide SOS to residential and small commercial customers until further action of the General Assembly. The legislation also provides for a customer refund reflecting the difference between the interest expense on an initially projected deferred balance at a 25% customer participation level and the interest expense on a deferred balance based on actual participation levels referred to above. The total amount of the refund is approximately $1.1 million for Pepco customers and approximately $.3 million for DPL customers. At Pepco's 2% level of participation, Pepco estimates that the deferral balance, net of taxes, will be approximately $1.4 million. At DPL's 1% level of participation, DPL estimates that the deferral balance, net of taxes, will be approximately $.2 million. In July 200 6, the MPSC approved revised tariff riders filed in June 2006 by Pepco and DPL to implement the legislation.

     Virginia

     On March 10, 2006, DPL filed for a rate increase with the VSCC for its Virginia Default Service customers to take effect on June 1, 2006, which was intended to allow DPL to recover its higher cost for energy established by the competitive bid procedure. On June 19, 2006, the VSCC issued an order that granted a rate increase for DPL of $11.5 million ($8.5 million less than requested by DPL in its March 2006 filing), to go into effect July 1, 2006. In determining the amount of the approved increase, the VSCC applied the proxy rate calculation to DPL's fuel factor, rather than allowing full recovery of the costs DPL incurred in procuring the supply necessary for its Default Service obligation. The estimated after-tax earnings and cash flow impacts of the decision are reductions of approximately $3.6 million in 2006 (including the loss

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of revenue in June 2006 associated with the Default Service rate increase being deferred from June 1 until July 1) and $2.0 million in 2007. The order also mandated that DPL file an application by March 1, 2007 (which has been delayed until April 2, 2007 by subsequent VSCC order) for Default Service rates to become effective June 1, 2007, which should include a calculation of the fuel factor that is consistent with the procedures set forth in the order.

     In February 2007, the Virginia General Assembly passed amendments to the Virginia Electric Utility Restructuring Act (the Virginia Restructuring Act) that modified the method by which investor-owned electric utilities in Virginia will be regulated by the VSCC. These amendments to the Virginia Restructuring Act, subject to further amendment or veto by the Virginia governor and subsequent action by the General Assembly, will be effective on July 1, 2007. The amendments provide that, as of December 31, 2008, the following will come to an end: (i) capped rates (the previous expiration date was December 31, 2010); (ii) DPL's Default Service obligation (previously, DPL was obligated to continue to offer Default Service until relieved of that obligation by the VSCC); and (iii) customer choice, except that customers with loads of 5 megawatts or greater will continue to be able to buy from competitive suppliers, as will smaller non-residential customers tha t aggregate their loads to reach the 5 megawatt threshold and obtain VSCC approval. Additionally, if an ex-customer of Default Service wants to return to DPL as its energy supplier, it must give 5 years notice or obtain approval of the VSCC that the return is in the public interest. In this event, the ex-customer must take DPL's service at market based rates. DPL also believes that the amendments to the Virginia Restructuring Act will terminate, as of December 31, 2008, the ratemaking provisions within the memorandum of agreement entered into by DPL, the staff of the VSCC and the Virginia Attorney General's office in the docket approving DPL's generating asset divestiture in 2000 (the MOA), including the application of the proxy rate calculation to DPL's fuel factor as discussed above; however, the VSCC's interpretation of these provisions is not known. It should be noted that in DPL's view, in the absence these amendments, the MOA and all of its provisions (including the proxy rate calculation) expire o n July 1, 2007; the VSCC staff and the Virginia Attorney General disagree with DPL's position. Assuming the ratemaking provisions of the MOA end on December 31, 2008 pursuant to the amended Virginia Restructuring Act, the amendments provide that DPL shall file a rate case in 2009 and every 2 years thereafter. The ROE to be allowed by the VSCC will be set within a range, the lower of which is essentially the average of vertically integrated investor-owned electric utilities in the southeast with an upper point that is 300 basis points above that average. The VSCC has authority to set rates higher or lower to allow DPL to maintain the opportunity to earn the determined ROE and to credit back to customers, in whole or in part, earnings that were 50 basis points or more in excess of the determined ROE. The amended Virginia Restructuring Act includes various incentive ROEs for the construction of new generation and would allow the VSCC to penalize or reward DPL for efficient operations or, if DPL were to add new generation, for generating unit performance. There are also enhanced ratemaking features if DPL pursues conservation, demand management and energy efficiency programs or pursues renewable energy portfolios.

ACE Sale of Generating Assets

     On September 1, 2006, ACE completed the sale of its interests in the Keystone and Conemaugh generating facilities to Duquesne Light Holdings Inc. for approximately $177.0 million, which was subsequently decreased by $1.6 million based on a post-closing 60-day true-up for applicable items not known at the time of the closing. Approximately $81.3 million of the net gain from the sale has been used to offset the remaining regulatory asset balance, which ACE

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has been recovering in rates, and approximately $49.8 million of the net gain is being returned to ratepayers over a 33-month period as a credit on their bills, which began with the October 2006 billing month. The balance to be repaid to customers is $48.4 million as of December 31, 2006.

     On February 8, 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy Investments, LLC, for a price of $9.0 million, after adjustment for, among other things, variances in the value of fuel and material inventories at the time of closing, plant operating capacity, the value of certain benefits for transferred employees and the actual closing date. The purchase price will be further adjusted based on a post-closing 60-day true-up for applicable items not known at the time of the closing. In addition, RC Cape May and ACE have agreed to arbitration concerning whether RC Cape May must pay to ACE, as part of the purchase price, an additional $3.1 million remaining in dispute. RC Cape May also assumed certain liabilities associated with the B.L. England generating station, including substantially all environmental liabilities. This transaction is further described below under the h eading "Environmental Litigation."

     The sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized. ACE anticipates that approximately $9 million to $10 million of additional regulatory assets related to B.L. England may, subject to NJBPU approval, be eligible for recovery as stranded costs. The emission allowance credits associated with B. L. England will be monetized for the benefit of ACE's ratepayers pursuant to the NJBPU order approving the sale. Net proceeds from the sale of the plant and monetization of the emission allowance credits, which will be determined after the sale upon resolution of certain adjustments, will be credited to ACE's ratepayers in accordance with the requirements of EDECA and NJBPU orders.

General Litigation

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

     Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed. As a result of two motions to dismiss, numerous hearings and meetings and one motion for summary judgment, Pepco has had approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of January 31, 2007, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland; of which 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. Under the terms of the Settlement Agreement, Mirant has agreed to assume this contractual obligation. For a description of the Settlement Agreement, see the discussion of the relationship with Mirant above.

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     While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) exceeds $360 million, PHI and Pepco believe 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, neither PHI nor Pepco believes these suits will have a material adverse effect on its financial position, results of operations or cash flows. However, if an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco's and PHI's financial position, results of operations or cash flows.

Cash Balance Plan Litigation

     In 1999, Conectiv established a cash balance retirement plan to replace defined benefit retirement plans then maintained by ACE and DPL. Following the acquisition by Pepco of Conectiv, this plan became the Conectiv Cash Balance Sub-Plan within the PHI Retirement Plan. On September 26, 2005, three management employees of PHI Service Company filed suit in the United States District Court for the District of Delaware (the Delaware District Court) against the PHI Retirement Plan, PHI and Conectiv (the PHI Parties), alleging violations of ERISA, on behalf of a class of management employees who did not have enough age and service when the Cash Balance Sub-Plan was implemented in 1999 to assure that their accrued benefits would be calculated pursuant to the terms of the predecessor plans sponsored by ACE and DPL. A fourth plaintiff was added to the case to represent DPL-heritage "grandfathered" employees who will not be eligible for early retirement at the end of the grandfathere d period.

     The plaintiffs have challenged the design of the Cash Balance Sub-Plan and are seeking a declaratory judgment that the Cash Balance Sub-Plan is invalid and that the accrued benefits of each member of the class should be calculated pursuant to the terms of the predecessor plans. Specifically, the complaint alleges that the use of a variable rate to compute the plaintiffs' accrued benefit under the Cash Balance Sub-Plan results in reductions in the accrued benefits that violate ERISA. The complaint also alleges that the benefit accrual rates and the minimal accrual requirements of the Cash Balance Sub-Plan violate ERISA as did the notice that was given to plan participants upon implementation of the Cash Balance Sub-Plan.

     The PHI Parties filed a motion to dismiss the suit, which was denied by the court on July 11, 2006. The Delaware District Court stayed one count of the complaint regarding alleged age discrimination pending a decision in another case before the United States Court of Appeals for the Third Circuit (the Third Circuit). On January 30, 2007, the Third Circuit issued a ruling in the other case that PHI's counsel believes should result in the favorable disposition of all of the claims (other than the claim of inadequate notice) against the PHI Parties in the Delaware District Court. The PHI Parties filed pleadings apprising the Delaware District Court of the Third Circuit's decision on February 16, 2007, at the same time they filed their opposition to plaintiffs' motion.

     While PHI believes it has an increasingly strong legal position in the case and that it is therefore unlikely that the plaintiffs will prevail, PHI estimates that, if the plaintiffs were to prevail, the ABO and projected benefit obligation (PBO), calculated in accordance with SFAS No. 87, each would increase by approximately $12 million, assuming no change in benefits for persons who have already retired or whose employment has been terminated and using actuarial valuation data as of the time the suit was filed. The ABO represents the present value that participants have earned as of the date of calculation. This means that only service already worked and compensation already earned and paid is considered. The PBO is similar to the

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ABO, except that the PBO includes recognition of the effect that estimated future pay increases would have on the pension plan obligation.

Environmental Litigation

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

     In July 2004, DPL entered into an administrative consent order (ACO) 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 a Cambridge, Maryland site on DPL-owned property and to investigate the extent of MGP contamination on adjacent property. The MDE has approved the RI and DPL submitted a final FS to MDE on February 15, 2007. The costs of cleanup (as determined by the RI/FS and subsequent negotiations with MDE) are anticipated to be approximately $2.7 million. The remedial action will include dredging activities within Cambridge Creek, which are expected to take place as early as October 2007, and soil excavation on DPL's and adjacent property as early as January 2008.

     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 the EPA that they, along with a number of other utilities and non-utilities, were potentially responsible parties (PRPs) in connection with the PCB contamination at the site.

     In 1994, an RI/FS including a number of possible remedies was submitted to the EPA. In 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 1998, the EPA issued a unilateral administrative order to Pepco and 12 other PRPs directing them to conduct the design and actions called for in its decision. In May 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. In October 2003, the bankruptcy court confirmed a reorganization plan that incorporates the terms of a settlement among the two debtor owner/operator entities, the United States and a group of utility PRPs including Pepco (the Utility PRPs). Under the bankruptcy settlement, the reorganized entity/site owner will pay a total of $13.25 million to remediate the site (the Bankruptcy Settlement).

     In March 2006, the United States District Court for the Eastern District of Pennsylvania approved global consent decrees for the Metal Bank/Cottman Avenue site, entered into on

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August 23, 2005, involving the Utility PRPs, the U.S. Department of Justice, EPA, The City of Philadelphia and two owner/operators of the site. Under the terms of the settlement, the two owner/operators will make payments totaling $5.55 million to the U.S. Department of Justice and totaling $4.05 million to the Utility PRPs. The Utility PRPs will perform the remedy at the site and will be able to draw on the $13.25 million from the Bankruptcy Settlement to accomplish the remediation (the Bankruptcy Funds). The Utility PRPs will contribute funds to the extent remediation costs exceed the Bankruptcy Funds available. The Utility PRPs also will be liable for EPA costs associated with overseeing the monitoring and operation of the site remedy after the remedy construction is certified to be complete and also the cost of performing the "5 year" review of site conditions required by the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Any Bankruptcy Funds not spent on the remed y may be used to cover the Utility PRPs' liabilities for future costs. No parties are released from potential liability for damages to natural resources.

     As of December 31, 2006, Pepco had accrued $1.7 million to meet its liability for a remedy at the Metal Bank/Cottman Avenue site. While final costs to Pepco of the settlement have not been determined, Pepco believes that its liability at this site will not have a material adverse effect on its financial position, results of operations or cash flows.

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

     In November 1991, the New Jersey Department of Environmental Protection (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 ACO 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. Positive results of groundwater monitoring events have resulted in a reduced level of groundwater monitoring. In August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site. Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years and to continue groundwater monitoring.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 anticipates that its share of additional cost associated with this site will be approximately $555,000 to $600,000. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial position, results of operations or cash flows.

     On January 24, 2006, PHI, Conectiv and ACE entered into an ACO with NJDEP and the Attorney General of New Jersey resolving (i) New Jersey's claim for alleged violations of the federal Clean Air Act (CAA) and (ii) the NJDEP's concerns regarding ACE's compliance with New Source Review requirements of the CAA and Air Pollution Control Act requirements with respect to the B.L. England generating facility and various other environmental issues

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relating to ACE and Conectiv Energy facilities in New Jersey. See Item 1 "Business -- Environmental Matters -- Air Quality Regulation."

Federal Tax Treatment of Cross-Border Leases

     PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which, as of December 31, 2006, had a book value of approximately $1.3 billion, and from which PHI currently derives approximately $57 million per year in tax benefits in the form of interest and depreciation deductions.

     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 entering into certain sale-leaseback transactions with tax-indifferent parties (i.e., municipalities, tax-exempt and governmental entities), including those entered into on or prior to March 12, 2004 (the Notice). All of PCI's cross-border energy leases are with tax indifferent parties and were entered into prior to 2004. In addition, on June 29, 2005 the IRS published a Coordinated Issue Paper concerning the resolution of audit issues related to such transactions. PCI's cross-border energy leases are similar to those sale-leaseback transactions described in the Notice and the Coordinated Issue Paper.

     PCI's leases have been under examination by the IRS as part of the normal PHI tax audit. On June 9, 2006, the IRS issued its final revenue agent's report (RAR) for its audit of PHI's 2001 and 2002 income tax returns. In the RAR, the IRS disallowed the tax benefits claimed by PHI with respect to these leases for those years. The tax benefits claimed by PHI with respect to these leases from 2001 through December 31, 2006 were approximately $287 million. PHI has filed a protest against the IRS adjustments and the unresolved audit has been forwarded to the Appeals Office. 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 financial condition, results of operations, and cash flows. PHI believes that its tax position related to these transactions was appropriate based on applicable statute s, regulations and case law, and intends to contest the adjustments proposed by the IRS; however, there is no assurance that PHI's position will prevail.

     On July 13, 2006, the FASB issued FSP FAS 13-2, which amends SFAS No. 13 effective for fiscal years beginning after December 15, 2006. This amendment requires a lease to be repriced and the book value adjusted when there is a change or probable change in the timing of tax benefits of the lease regardless of whether the change results in a deferral or permanent loss of tax benefits. Accordingly, a material change in the timing of cash flows under PHI's cross-border leases as the result of a settlement with the IRS would require an adjustment to the book value of the leases and a charge to earnings equal to the repricing impact of the disallowed deductions which could result in a material adverse effect on PHI's financial condition, results of operations, and cash flows. PHI believes its tax position was appropriate and at this time does not believe there is a probable change in the timing of its tax benefits that would require repricing the leases and a charge to earnings.

     On February 1, 2007 the U.S. Senate passed the Small Business and Work Opportunity Act of 2007. Included in this legislation is a provision which would apply passive loss limitation rules to leases with foreign tax indifferent parties effective for taxable years beginning after December 31, 2006, even if the leases were entered into on or prior to March 12, 2004. On February 16, 2007, the U.S. House of Representatives passed the Small Business Relief Act of

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2007. This bill does not include any provision that would modify the current treatment of leases with tax indifferent parties. Enactment into law of a bill that is similar to that passed by the U.S. Senate in its current form could result in a material delay of the income tax benefits that PCI would receive in connection with its cross-border energy leases. Furthermore, under FSP FAS 13-2, PHI would be required to adjust the book values of its leases and record a charge to earnings equal to the repricing impact of the disallowed deductions which could result in a material adverse effect on PHI's financial condition, results of operations and cash flows. The U.S. House of Representatives and the U.S. Senate are expected to hold a conference in the near future to reconcile the differences in the two bills to determine the final legislation.

IRS Mixed Service Cost Issue

     During 2001, Pepco, DPL, and ACE changed their methods of accounting with respect to capitalizable construction costs for income tax purposes. The change allowed the companies to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through December 31, 2005, these accelerated deductions generated incremental tax cash flow benefits of approximately $205 million (consisting of $94 million for Pepco, $62 million for DPL, and $49 million for ACE) for the companies, primarily attributable to their 2001 tax returns.

     On August 2, 2005, the Treasury Department released regulations that, if adopted in their current form, would require Pepco, DPL, and ACE to change their method of accounting with respect to capitalizable construction costs for income tax purposes for tax periods beginning in 2005. Based on those regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believes will be acceptable to the IRS.

     On the same day that the new regulations were released, the IRS issued Revenue Ruling 2005-53, which is intended to limit the ability of certain taxpayers to utilize the method of accounting for income tax purposes they utilized on their tax returns for 2004 and prior years with respect to capitalizable construction costs. In line with this Revenue Ruling, the IRS RAR for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that Pepco, DPL and ACE had claimed on those returns by requiring the companies to capitalize and depreciate certain expenses rather than treat such expenses as current deductions. PHI's protest of the IRS adjustments is among the unresolved audit matters relating to the 2001 and 2002 audits pending before the Appeals Office.

     In February 2006, PHI paid approximately $121 million of taxes to cover the amount of taxes that management estimated to be payable based on the method of tax accounting that PHI, pursuant to the proposed regulations, has adopted on its 2005 tax return. However, if the IRS is successful in requiring Pepco, DPL and ACE to capitalize and depreciate construction costs that result in a tax and interest assessment greater than management's estimate of $121 million, PHI will be required to pay additional taxes and interest only to the extent these adjustments exceed the $121 million payment made in February 2006.

IRS Examination of Like-Kind Exchange Transaction

     In 2001, Conectiv and certain of its subsidiaries (the Conectiv Group) were divesting nonstrategic electric generating facilities and replacing these facilities with mid-merit electric generating capacity. As part of this strategy, the Conectiv Group exchanged its interests in two

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older coal-fired plants for the more efficient gas-fired Hay Road II generating facility, which was owned by an unaffiliated third party. For tax purposes, Conectiv treated the transaction as a "like-kind exchange" under IRC Section 1031. As a result, approximately $88 million of taxable gain was deferred for federal income tax purposes.

     The transaction was examined by the IRS as part of the normal Conectiv tax audit. In May 2006, the IRS issued its RAR for the audit of Conectiv's 2000, 2001 and 2002 income tax returns. In the RAR, the IRS exam team disallowed the qualification of the exchange under IRC Section 1031. In July 2006, Conectiv filed a protest of this disallowance to the IRS Office of Appeals.

     PHI believes that its tax position related to this transaction is proper based on applicable statutes, regulations and case law and intends to vigorously contest the disallowance. However, there is no absolute assurance that Conectiv's position will prevail. If the IRS prevails, Conectiv would be subject to additional income taxes, interest and possible penalties. However, a portion of the denied benefit would be offset by additional tax depreciation.

     As of December 31, 2006, if the IRS fully prevails, the potential cash impact on PHI would be current income tax and interest payments of approximately $29 million and the earnings impact would be approximately $7 million in after-tax interest.

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, 2006, Pepco Holdings and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, performance residual value, and other commitments and obligations. The fair value of these commitments and obligations was not required to be recorded in Pepco Holdings' Consolidated Balance Sheets; however, certain energy marketing obligations of Conectiv Energy were recorded. The commitments and obligations, in millions of dollars, were as follows:

	Guarantor
		PHI		DPL		ACE		Other		Total
Energy marketing obligations of Conectiv Energy (1)	$	100.9	$	-	$	-	$	-	$	100.9
Energy procurement obligations ofPepco Energy Services (1)		206.7		-		-		-		206.7
Guaranteed lease residual values (2)		.5		3.3		3.2		-		7.0
Other (3)		2.9		-		-		1.9		4.8
Total	$	311.0	$	3.3	$	3.2	$	1.9	$	319.4

1.	Pepco Holdings has contractual commitments for performance and related payments of Conectiv Energy and Pepco Energy Services to counterparties related to routine energy sales and procurement obligations, including retail customer load obligations and requirements under BGS contracts entered into with ACE.
2.	Subsidiaries of Pepco Holdings have guaranteed residual values in excess of fair value related to certain equipment and fleet vehicles held through lease agreements. As of December 31, 2006, obligations under the guarantees were approximately $7.0 million. Assets leased under agreements subject to residual value guarantees are typically for periods ranging from 2 years to 10 years. Historically, payments under the guarantees
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	have not been made by the guarantor as, under normal conditions, the contract runs to full term at which time the residual value is minimal. As such, Pepco Holdings believes the likelihood of payment being required under the guarantee is remote.
3.	Other guarantees consist of:
	·	Pepco Holdings has guaranteed a subsidiary building lease of $2.9 million. Pepco Holdings does not expect to fund the full amount of the exposure under the guarantee.
	·	PCI has guaranteed facility rental obligations related to contracts entered into by Starpower. As of December 31, 2006, the guarantees cover the remaining $1.9 million in rental obligations.

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

Dividends

     On January 25, 2007, the Board of Directors declared a dividend on common stock of 26 cents per share payable March 30, 2007, to shareholders of record March 12, 2007.

Contractual Obligations

     As of December 31, 2006, Pepco Holdings' contractual obligations under non-derivative fuel and purchase power contracts, excluding the Panda PPA discussed above under "Relationship with Mirant Corporation" and BGS supplier load commitments, were $2,716.2 million in 2007, $2,303.8 million in 2008 to 2009, $742.7 million in 2010 to 2011, and $2,791.8 million in 2012 and thereafter.

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

     PHI's Competitive Energy businesses 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 businesses include forward contracts, futures, swaps, and exchange-traded and over-the-counter options. In addition, the Competitive Energy businesses also manage commodity risk with contracts that are not classified as derivatives. The two primary risk management objectives are (1) 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 (2) to manage the spread between retail sales commitments and the cost of supply used to service those commitments. To a lesser extent, Conectiv Energy also engages in market activities in an effort to profit from

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short-term price differentials in electricity prices between different locations. PHI collectively refers to these energy market activities, including its commodity risk management activities, as "other energy commodity" activities and identifies this activity separately from that of the discontinued proprietary trading activity described below.

     Pepco Holdings' subsidiaries attempt to minimize credit risk exposure to wholesale energy counterparties through, among other things, formal credit policies, regular assessment of counterparty creditworthiness and 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.

     PHI and its subsidiaries also use derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt incurred in connection with the operation of their businesses. In June 2002, PHI entered into several treasury lock transactions in anticipation of the issuance of several series of fixed rate debt commencing in July 2002. There remained a loss balance of $33.1 million in Accumulated Other Comprehensive Income (AOCI) at December 31, 2006 related to this transaction. The portion expected to be reclassified to earnings during the next 12 months is $5.6 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 No. 133 included in PHI's Consolidated Balance Sheet as of December 31, 2006. Under SFAS No. 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, 2006 (Millions of dollars)
Contracts		Accumulated OCI    (Loss) After-tax (1)	Portion Expected to be Reclassified to Earnings during the Next 12 Months	Maximum Term
Other Energy Commodity		$(61.9)	$(18.1)	63 months
Interest Rate		(33.1)	(5.6)	308 months
Total		$(95.0)	$(23.7)
(1)	Accumulated Other Comprehensive Loss as of December 31, 2006, includes an $(8.4) million balance related to minimum pension liability. This balance is not included in this table as there is not a cash flow hedge associated with it.

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     The following table shows, in millions of dollars, the pre-tax gain (loss) recognized in earnings for cash flow hedge ineffectiveness for the years ended December 31, 2006, 2005, and 2004, and where they were reported in the Consolidated Statements of Earnings during the period.

	2006	2005	2004
Operating Revenue	$   .4	$  3.0	$   2.5
Fuel and Purchased Energy Expenses	(.3)	(2.7)	(8.5)
Total	$   .1	$    .3	$ (6.0)

     In connection with their energy commodity activities, the Competitive Energy businesses designate certain derivatives as fair value hedges. The net pre-tax gains/(losses) recognized during the twelve months ended December 31, 2006, 2005 and 2004 included in the Consolidated Statements of Earnings for fair value hedges and the associated hedged items are shown in the following table (in millions of dollars).

	2006	2005	2004
Gain/(Loss) on Derivative Instruments	.2	-	-
Gain/Loss on Hedged Items	(.2)	-	-

     For the year ended 2006, a $.3 million loss was reclassified from other comprehensive income (OCI) to earnings because the forecasted hedged transactions were deemed to be no longer probable. For the year ended 2005, there were no forecasted hedged transactions or firm commitments deemed to be no longer probable.

     In connection with their other energy commodity activities, the Competitive Energy businesses hold certain derivatives that do not qualify as hedges. Under SFAS No. 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 included in "Competitive Energy Operating Revenues" and are summarized in the following table, in millions of dollars, for the years ended December 31, 2006, 2005, and 2004.

	2006	2005	2004
Proprietary Trading	$     -	$  .1	$ (.4)
Other Energy Commodity	64.7	37.8	24.2
Total	$64.7(1)	$37.9	$23.8
(1) Includes $.3 million of ineffective fair value hedges.

(14)  EXTRAORDINARY ITEM

     On April 19, 2005, ACE, the staff of the NJBPU, the New Jersey Ratepayer Advocate, and active intervenor parties agreed on a settlement in ACE's electric distribution rate case. As a result of this settlement, ACE reversed $15.2 million in accruals related to certain deferred costs that are now deemed recoverable. The after-tax credit to income of $9.0 million is classified as an extraordinary gain in the 2005 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.

	2006
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Total
	(Millions, except per share amounts)
Total Operating Revenue	$1,951.9	$1,916.6	$2,589.9	$1,904.5	$8,362.9
Total Operating Expenses	1,798.0	1,753.4	2,347.1	1,771.1	7,669.6 (b)
Operating Income	153.9	163.2	242.8	133.4	693.3
Other Expenses	(61.5) (a)	(72.5)	(76.2)	(72.2)	(282.4)
Preferred Stock Dividend   Requirements of Subsidiaries	.4	.3	.3	.2	1.2
Income Before Income Tax Expense	92.0	90.4	166.3	61.0	409.7
Income Tax Expense	35.2	39.2	62.3	24.7	161.4
Net Income	56.8	51.2	104.0	36.3	248.3
Basic and Diluted Earnings   Per Share of Common Stock	$     .29	$       .27	$       .54	$       .19	$     1.30
Cash Dividends Per Common Share	$     .26	$       .26	$       .26	$       .26	$     1.04

	2005
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Total
	(Millions, except per share amounts)
Total Operating Revenue	$1,798.8	$1,720.2	$2,483.6	$2,062.9	$  8,065.5
Total Operating Expenses	1,654.1	1,535.8	2,115.3(e)	1,854.9(f)(g)	7,160.1
Operating Income	144.7	184.4	368.3	208.0	905.4
Other Expenses	(67.8)	(74.8)	(72.4)	(70.5)	(285.5)
Preferred Stock Dividend   Requirements of Subsidiaries	.6	.7	.6	.6	2.5
Income Before Income Tax   Expense	76.3	108.9	295.3	136.9	617.4
Income Tax Expense	30.6	42.5	127.3(d)	54.8(h)	255.2
Income Before Extraordinary Item	45.7	66.4	168.0	82.1	362.2
Extraordinary Item (c)	9.0	-	-	-	9.0
Net Income	54.7	66.4	168.0	82.1	371.2
Basic and Diluted Earnings   Per Share of Common Stock   Before Extraordinary Item	.24	.35	.89	.43	1.91
Extraordinary Item Per   Share of Common Stock	.05	-	-	-	.05
Basic and Diluted Earnings   Per Share of Common Stock	$      .29	$     .35	$     .89	$       .43	$     1.96
Cash Dividends Per Common Share	$      .25	$     .25	$     .25	$       .25	$     1.00

(a)	Includes $12.3 million gain ($7.9 million after-tax) on the sale of its equity interest in a joint venture which owns a wood burning cogeneration facility in California.
(b)	Includes $18.9 million of impairment losses ($13.7 million after-tax) related to certain energy services business assets.
(c)	Relates to ACE's electric distribution rate case settlement that was accounted for in the first quarter of 2005. This resulted in ACE's reversal of $9.0 million in after-tax accruals related to certain deferred costs that are now deemed recoverable. This amount is classified as an extraordinary gain since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.
(d)	Includes $8.3 million in income tax expense related to the mixed service cost issue under IRS Ruling 2005-53.
(e)	Includes $68.1 million gain ($40.7 million after-tax) from sale of non-utility land owned by Pepco at Buzzard Point.
(f)	Includes $70.5 million ($42.2 million after-tax) gain (net of customer sharing) from settlement of the Pepco TPA Claim and the Pepco asbestos claim against the Mirant bankruptcy estate.
(g)	Includes $13.3 million gain ($8.9 million after-tax) recorded by PCI's liquidation of a financial investment that was written off in 2001.
(h)	Includes $2.6 million in income tax expense related to IRS Ruling 2005-53.

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(16)  SUBSEQUENT EVENTS

     On January 18, 2007, DPL redeemed all outstanding shares of its Redeemable Serial Preferred Stock of each series at redemption prices ranging from 103% to 105% of par, for an aggregate redemption amount of approximately $18.9 million.

     On February 8, 2007, ACE completed the sale of the B.L. England generating facility for a price of $9.0 million, subject to adjustment.

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Report of Independent Registered Public Accounting Firm

To the Shareholder and Board of Directors
of Potomac Electric Power Company:

In our opinion, the 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.) at December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006 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 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 statement schedule based on our audits. We conducted our audits of these statements in accordan ce 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.

PricewaterhouseCoopers LLP
Washington, DC
March 1, 2007

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POTOMAC ELECTRIC POWER COMPANY STATEMENTS OF EARNINGS
For the Year Ended December 31,		2006		2005		2004
(Millions of dollars)
Operating Revenue	$	2,216.5	$	1,845.3	$	1,805.9
Operating Expenses
Fuel and purchased energy		1,299.7		913.7		898.2
Other operation and maintenance		277.3		280.3		273.2
Depreciation and amortization		166.2		161.8		166.3
Other taxes		273.1		276.1		249.0
Gain on sales of assets		-		(72.4)		(6.9)
Gain on settlement of claims with Mirant		-		(70.5)		-
Total Operating Expenses		2,016.3		1,489.0		1,579.8
Operating Income		200.2		356.3		226.1
Other Income (Expenses)
Interest and dividend income		5.7		4.8		.9
Interest expense		(75.5)		(81.0)		(81.2)
Other income		13.1		13.8		8.3
Other expense		(.7)		(1.3)		(1.9)
Total Other Expenses		(57.4)		(63.7)		(73.9)
Income Before Income Tax Expense		142.8		292.6		152.2
Income Tax Expense		57.4		127.6		55.7
Net Income		85.4		165.0		96.5
Dividends on Serial Preferred Stock		1.0		1.3		1.0
Earnings Available for Common Stock	$	84.4	$	163.7	$	95.5
The accompanying Notes are an integral part of these Financial Statements.

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POTOMAC ELECTRIC POWER COMPANY STATEMENTS OF COMPREHENSIVE EARNINGS
For the Year Ended December 31,	2006	2005	2004
(Millions of dollars)
Net income	$85.4	$165.0	$96.5
Minimum pension liability adjustment, before income taxes	5.7	(4.5)	(1.2)
Income tax expense (benefit)	2.3	(1.8)	(.5)
Other comprehensive earnings (losses), net of income taxes	3.4	(2.7)	(.7)
Comprehensive earnings	$88.8	$162.3	$95.8
The accompanying Notes are an integral part of these Financial Statements.

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POTOMAC ELECTRIC POWER COMPANY BALANCE SHEETS
ASSETS	December 31, 2006		December 31, 2005
(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$     12.4	$    131.4
Accounts receivable, less allowance for uncollectible      accounts of $17.4 million and $14.1 million, respectively		318.3	339.0
Materials and supplies - at average cost		42.8	36.8
Prepayments of income taxes		66.5	-
Prepaid expenses and other		25.5	11.7
Total Current Assets		465.5	518.9
INVESTMENTS AND OTHER ASSETS
Regulatory assets		127.7	150.7
Prepaid pension expense		160.1	161.3
Investment in trust		29.0	53.1
Other		99.6	69.0
Total Investments and Other Assets		416.4	434.1
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		5,157.6	4,990.0
Accumulated depreciation		(2,162.5)	(2,068.0)
Net Property, Plant and Equipment		2,995.1	2,922.0
TOTAL ASSETS		$3,877.0	$3,875.0
The accompanying Notes are an integral part of these Financial Statements.

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POTOMAC ELECTRIC POWER COMPANY BALANCE SHEETS
LIABILITIES AND SHAREHOLDER'S EQUITY	December 31, 2006	December 31, 2005
(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$     67.1	$           -
Current maturities of long-term debt	210.0	50.0
Accounts payable and accrued liabilities	180.1	185.3
Accounts payable to associated companies	46.0	40.3
Capital lease obligations due within one year	5.5	5.1
Taxes accrued	72.8	173.2
Interest accrued	16.9	18.9
Other	153.6	81.2
Total Current Liabilities	752.0	554.0
DEFERRED CREDITS
Regulatory liabilities	146.8	145.2
Income taxes	636.3	622.0
Investment tax credits	14.5	16.5
Other postretirement benefit obligation	69.3	46.7
Other	66.0	75.9
Total Deferred Credits	932.9	906.3
LONG-TERM LIABILITIES
Long-term debt	990.0	1,198.9
Capital lease obligations	110.9	116.3
Total Long-Term Liabilities	1,100.9	1,315.2
COMMITMENTS AND CONTINGENCIES (NOTE 11)
SERIAL PREFERRED STOCK	-	21.5
SHAREHOLDER'S EQUITY
Common stock, $.01 par value, authorized 400,000,000 shares,      issued 100 shares	-	-
Premium on stock and other capital contributions	531.5	507.1
Accumulated other comprehensive loss	-	(3.4)
Retained earnings	559.7	574.3
Total Shareholder's Equity	1,091.2	1,078.0
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$3,877.0	$3,875.0
The accompanying Notes are an integral part of these Financial Statements.

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POTOMAC ELECTRIC POWER COMPANY STATEMENTS OF CASH FLOWS
For the Year Ended December 31,	2006		2005	2004
(Millions of dollars)
OPERATING ACTIVITIES
Net Income	$  85.4		$ 165.0	$   96.5
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	166.2		161.8	166.3
Gain on sale of assets	-		(72.4)	(6.9)
Gain on settlement of claims with Mirant	-		(70.5)	-
Deferred income taxes	38.0		(49.8)	24.8
Investment tax credit adjustments, net	(2.0)		(2.0)	(2.0)
Prepaid pension expense	12.2		9.8	(2.9)
Other postretirement benefit obligation	(.7)		2.9	(.5)
Other deferred charges	(3.9)		17.0	(8.9)
Other deferred credits	(3.0)		(3.6)	3.4
Changes in:
Accounts receivable	20.6		(26.3)	(31.3)
Regulatory assets and liabilities, net	(18.5)		(45.1)	(35.8)
Prepaid expenses	(1.2)		(.9)	20.1
Accounts payable and accrued liabilities	(27.8)		59.8	(9.4)
Interest and taxes accrued	(172.2)		100.6	49.6
Materials and supplies	(6.0)		1.4	3.0
Proceeds from Mirant settlement	70.0		-	-
Proceeds from sale of claims with Mirant	-		112.9	-
Net Cash From Operating Activities	157.1		360.6	266.0
INVESTING ACTIVITIES
Investment in property, plant and equipment	(204.9)		(177.7)	(204.1)
Proceeds from/changes in:
Proceeds from sale of other assets	-		78.0	-
Proceeds from sale of other investments	-		-	22.4
Net other investing activity	28.5		(.2)	(.2)
Net Cash Used By Investing Activities	(176.4)		(99.9)	(181.9)
FINANCING ACTIVITIES
Dividends paid to Pepco Holdings	(99.0)		(62.9)	(102.4)
Dividends paid on Pepco preferred stock	(1.0)		(1.3)	(1.0)
Issuances of long-term debt	109.5		175.0	375.0
Redemption of long-term debt	(159.5)		(225.0)	(210.0)
Issuances (repayments) of short-term debt, net	67.1		(14.0)	(93.5)
Redemption of preferred stock	(21.5)		(5.5)	(53.3)
Net other financing activities	4.7		2.9	(4.2)
Net Cash Used By Financing Activities	(99.7)		(130.8)	(89.4)
Net (Decrease) Increase in Cash and Cash Equivalents	(119.0)		129.9	(5.3)
Cash and Cash Equivalents at Beginning of Year	131.4		1.5	6.8
CASH AND CASH EQUIVALENTS AT END OF YEAR	$  12.4	$	$ 131.4	$    1.5
NONCASH ACTIVITIES
Asset retirement obligations associated with removal     costs transferred to regulatory liabilities	$  27.7		$ (12.3)	$     .8
Capital contribution in respect of certain intercompany transactions	$  24.1		$        -	$      -
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $1.5 million, $1.6     million and $1.2 million, respectively) and paid for income taxes:
Interest	$  73.4		$   77.8	$   76.5
Income taxes	$128.1		$   80.3	$   10.6
The accompanying Notes are an integral part of these Financial Statements.

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POTOMAC ELECTRIC POWER COMPANY STATEMENTS OF SHAREHOLDER'S EQUITY
	Common Stock   Shares   Par Value		Premium on Stock	Capital Stock Expense	Accumulated Other Comprehensive Earnings (Loss)	Retained Earnings
(Millions of dollars, except shares)
BALANCE, DECEMBER 31, 2003	100	$     -	$  507.6	$ (1.1)	$    -	$482.5
Net Income	-	-	-	-	-	96.5
Other comprehensive loss	-	-	-	-	(.7)	-
Dividends:
Preferred stock	-	-	-	-	-	(1.0)
To Pepco Holdings	-	-	-	-	-	(102.4)
Of Investment to Pepco Holdings	-	-	-	-	-	(2.1)
Preferred stock repurchase	-	-	(.1)	.2	-	-
Preferred stock redemption	-	-	-	.4	-	-
BALANCE, DECEMBER 31, 2004	100	$     -	$  507.5	$  (.5)	$ (.7)	$473.5
Net Income	-	-	-	-	-	165.0
Other comprehensive loss	-	-	-	-	(2.7)	-
Dividends:
Preferred stock	-	-	-	-	-	(1.3)
To Pepco Holdings	-	-	-	-	-	(62.9)
Preferred stock redemption	-	-	-	.1	-	-
BALANCE, DECEMBER 31, 2005	100	$     -	$  507.5	$  (.4)	$(3.4)	$574.3
Net Income	-	-	-	-	-	85.4
Other comprehensive earnings	-	-	-	-	3.4	-
Dividends:
Preferred stock	-	-	-	-	-	(1.0)
To Pepco Holdings	-	-	-	-	-	(99.0)
Capital contributions	-	-	24.1	-	-	-
Preferred stock redemption	-	-	(.1)	.4	-	-
BALANCE, DECEMBER 31, 2006	100	$     -	$  531.5	$    -	$    -	$559.7
The accompanying Notes are an integral part of these Financial Statements.

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NOTES TO FINANCIAL STATEMENTS

POTOMAC ELECTRIC POWER COMPANY

(1)  ORGANIZATION

     Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in Washington, D.C. and major portions of Prince George's and Montgomery Counties in suburban Maryland. Pepco provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier, in both the District of Columbia and Maryland. Default Electricity Supply is known as Standard Offer Service (SOS) in both the District of Columbia and Maryland. Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (Pepco Holdings or PHI). Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between PHI and Pepco and certain activities of Pepco are subject to the regulatory oversight of the Federal Energy Regulatory Commission (FERC) under PUHCA 2005.

(2)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP), 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 financial statements and accompanying notes. Examples of significant estimates used by Pepco include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, and income tax provision and reserves. Additionally, Pepco is subject to legal, regulatory, and other proceedings and claims that arise in the or dinary course of its business. Pepco records an estimated liability for these proceedings and claims based upon the probable and reasonably estimable criteria contained in Statement of Financial Accounting Standards (SFAS) No. 5, "Accounting for Contingencies." Although Pepco believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Adjustment to Pepco's Previously Recorded Delivery Taxes

     In 2006, Pepco recorded an adjustment to correct previously recorded District of Columbia delivery tax amounts. This adjustment reduced Pepco's earnings for the twelve months ended December 31, 2006 by $2.9 million.

Change in Accounting Estimates

     During 2005, Pepco recorded the impact of an increase in estimated unbilled revenue, primarily reflecting a change in Pepco's unbilled revenue estimation process. This modification

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in accounting estimate increased Pepco's net earnings for the year ended December 31, 2005 by approximately $2.2 million.

Revenue Recognition

     Pepco recognizes revenue for the supply and delivery of electricity upon delivery to its customers, including amounts for services rendered, but not yet billed (unbilled revenue). Pepco recorded amounts for unbilled revenue of $82.0 million and $92.6 million as of December 31, 2006 and 2005, respectively. These amounts are included in the "accounts receivable" line item in the accompanying balance sheets. Pepco calculates unbilled revenue using an output based methodology. This methodology is based on the supply of electricity or gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix and estimated power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers), which are inherently uncertain and susceptible to change from period to period, the impact of which could be material.

     The taxes related to the consumption of electricity by its customers, such as fuel, energy, or other similar taxes, are components of Pepco's tariffs and, as such, are billed to customers and recorded in Operating Revenues. Accruals for these taxes by Pepco are recorded in Other Taxes. Excise tax related generally to the consumption of gasoline by Pepco in the normal course of business is charged to operations, maintenance or construction, and is de minimis.

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 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 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 must be charged to earnings.

     The components of Pepco's regulatory asset balances at December 31, 2006 and 2005, are as follows:

	2006	2005
	(Millions of dollars)
Deferred recoverable income taxes	$  34.9	$  53.7
Deferred debt extinguishment costs	42.7	43.7
Phase in credits	1.3	-
Other	48.8	53.3
Total regulatory assets	$127.7	$150.7

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     The components of Pepco's regulatory liability balances at December 31, 2006 and 2005, are as follows:

	2006	2005
	(Millions of dollars)
Deferred income taxes due to customers	$  29.9	$  33.4
Generation Procurement Credit, customer sharing   commitment, and other	24.2	46.8
Accrued asset removal costs	92.7	65.0
Total regulatory liabilities	$146.8	$145.2

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

     Deferred Recoverable Income Taxes:Represents a receivable from our customers for tax benefits Pepco has previously flowed through before the company was ordered to provide deferred income taxes. As the temporary differences between the financial statement and tax basis of assets reverse, the deferred recoverable balances are reversed. 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.

     Phase In Credits: This is a phase in credit for Maryland customers to mitigate significant rate increases. The deferral period is June 1, 2006 - June 1, 2007. The recovery period is over an 18-month period beginning June 2007. Customers are required to "opt in." Recovery is rate per kilowatt hour, based on usage in recovery. 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 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.

     Generation Procurement Credit (GPC) and Customer Sharing Commitment: 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 from February 8, 2001 through February 7, 2005 in each jurisdiction. The GPC represents the customers' share of profits that Pepco has realized on the procurement and resale of SOS electricity supply to customers in Maryland and the District of Columbia that has not yet been distributed to customers. Pepco is currently distributing the customers' share of profits monthly to customers in a billing credit.

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     Accrued Asset Removal Costs: Represents Pepco's asset retirement obligation associated with removal costs accrued using public service commission approved depreciation rates for transmission, distribution, and general utility property.

Asset Retirement Obligations

     In accordance with SFAS No. 143, "Accounting for Asset Retirement Obligations" and Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 47, asset removal costs are recorded as regulatory liabilities. At December 31, 2006 and 2005, $92.7 million and $65.0 million, respectively, are reflected as regulatory liabilities in the accompanying Balance Sheets. Additionally, in 2005, Pepco recorded immaterial conditional asset retirement obligations for underground storage tanks. Accretion for these asset retirement obligations has been recorded as a regulatory asset.

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 Pepco and certain other PHI 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 money pool were $.4 million and $73.1 million at December 31, 2006 and 2005, respectively.

Accounts Receivable and Allowance for Uncollectible Accounts

     Pepco'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 after the receivable is recorded). Pepco uses the allowance method to account for uncollectible accounts receivable.

Investment in Trust

     Represents assets held in a trust for the benefit of participants in the Pepco Owned Life Insurance plan.

Capitalized Interest and Allowance for Funds Used During Construction

     In accordance with the provisions of SFAS No. 71, utilities can capitalize as Allowance for Funds Used During Construction (AFUDC) the capital costs of financing the construction of plant and equipment. The debt portion of AFUDC is recorded as a reduction of "interest expense" and the equity portion of AFUDC is credited to "other income" in the accompanying Statements of Earnings.

     Pepco recorded AFUDC for borrowed funds of $1.5 million, $1.6 million, and $1.2 million for the years ended December 31, 2006, 2005, and 2004, respectively.

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     Pepco recorded amounts for the equity component of AFUDC of $2.6 million, $2.6 million, and $2.0 million for the years ended December 31, 2006, 2005, and 2004, respectively.

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 2004, PHI's Power Delivery business reduced its work force 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. A roll forward of Pepco's severance accrual balance is as follows (Millions of dollars).

Balance, December 31, 2004	$  2.2
Accrued during 2005	(.1)
Payments/reversals during 2005	(2.1)
Balance, December 31, 2005	-
Accrued during 2006	1.6
Payments during 2006	(.1)
Balance, December 31, 2006	$  1.5

     Based on the number of employees that have accepted or are expected to accept the severance packages, substantially all of the severance liability will be paid by the end of 2007. Employees have the option of taking severance payments in a lump sum or over a period of time.

Pension and Other Postretirement Benefit Plans

     Pepco Holdings sponsors a retirement plan that covers substantially all employees of Pepco (the PHI Retirement Plan) and certain employees of other Pepco Holdings subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.

     The PHI Retirement Plan is accounted for in accordance with SFAS No. 87, "Employers' Accounting for Pensions," and its other postretirement benefits in accordance with SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." Pepco Holdings' financial statement disclosures were prepared in accordance with SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits."

     SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R)"

     In September 2006, the FASB issued SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R)." SFAS No. 158 requires that companies recognize a net liability or asset to report the funded status of their defined benefit pension and other postretirement benefit

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plans on the balance sheet. Recognizing the funded status of the company's benefit plans as a net liability or asset will require an offsetting adjustment to accumulated other comprehensive income in shareholders' equity or will be deferred as a regulatory asset or liability if probable of recovery in rates under SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS No.158 does not change how pension and other postretirement benefits are accounted for and reported in the income statement.

     Pepco participates in benefit plans sponsored by Pepco Holdings and as such, the provisions of SFAS No. 158 do not have an impact on its financial condition and cash flows.

Long-Lived Asset Impairment Evaluation

     Pepco is required to evaluate certain assets that have long lives (for example, 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 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 be recognized only 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, see the "Asset Retirement Obligations" section included in this Note.

     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. Property, plant and equipment other than electric facilities is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite depreciation rates for 2006, 2005, and 2004 for Pepco's transmission and distribution system property were approximately 3.5%, 3.4%, and 3.5%, respectively.

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 amounts, determined on a separate return basis.

     The 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.

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     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 Balance Sheets. For additional information, see the discussion under "Regulation of Power Delivery Operations" 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 Balance Sheets as "Investment tax credits." These investment tax credits are being amortized to income over the useful lives of the related utility plant.

FIN 46R, "Consolidation of Variable Interest Entities"

     Due to a variable element in the pricing structure of Pepco's purchase power agreement (Panda PPA) with Panda-Brandywine, L.P. (Panda), Pepco potentially assumes the variability in the operations of the plants related to this PPA and therefore has a variable interest in the entity. In accordance with the provisions of FIN 46R (revised December 2003), entitled "Consolidation of Variable Interest Entities," (FIN 46R), Pepco continued, during the year ended December 31, 2006, to conduct exhaustive efforts to obtain information from this entity, but was unable to obtain sufficient information to conduct the analysis required under FIN 46R to determine whether the entity was a variable interest entity or if Pepco was the primary beneficiary. As a result, Pepco has applied the scope exemption from the application of FIN 46R for enterprises that have conducted exhaustive efforts to obtain the necessary information, but have not been able to obtain such information.

     Power purchases related to the Panda PPA for the years ended December 31, 2006, 2005 and 2004, were approximately $79 million, $91 million and $76 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 other miscellaneous liabilities. The $70 million paid pursuant to the Settlement Agreement and Release with Mirant Corporation, its predecessors, its subsidiaries and successors (Mirant) (the Settlement Agreement) was included in the 2006 balance.

Other Deferred Credits

     The other deferred credits balance principally consists of miscellaneous deferred liabilities.

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Dividend Restrictions

     In addition to its future financial performance, the ability of Pepco 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, may require the prior approval of Pepco's utility regulatory commissions before dividends can be paid and (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by Pepco and any other restrictions imposed in connection with the incurrence of liabilities. Pepco had approximately $11.7 million and $41.0 million of restricted retained earnings at December 31, 2006 and 2005, respectively.

Reclassifications

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

New Accounting Standards

     FSP FTB 85-4-1, "Accounting for Life Settlement Contracts by Third-Party Investors"

     In March 2006, the FASB issued FASB Staff Position (FSP) FASB Technical Bulletin (FTB) 85-4-1, "Accounting for Life Settlement Contracts by Third-Party Investors" (FSP FTB 85-4-1). This FSP provides initial and subsequent measurement guidance and financial statement presentation and disclosure guidance for investments by third-party investors in life settlement contracts. FSP FTB 85-4-1 also amends certain provisions of FASB Technical Bulletin No. 85-4, "Accounting for Purchases of Life Insurance," and SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The guidance in FSP FTB 85-4-1 applies prospectively for all new life settlement contracts and is effective for fiscal years beginning after June 15, 2006 (the year ending December 31, 2007 for Pepco). Pepco has evaluated the impact of FSP FTB 85-4-1 and does not anticipate its adoption will have a material impact on its overall financial condition, results of operations, or cash flows.

     EITF 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

     In September 2005, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty" (EITF 04-13), which addresses circumstances under which two or more exchange transactions involving inventory with the same counterparty should be viewed as a single exchange transaction for the purposes of evaluating the effect of Accounting Principles Board Opinion 29, "Accounting for Nonmonetary Transactions." EITF 04-13 is effective for new arrangements entered into, or modifications or renewals of existing arrangements, beginning in the first interim or annual reporting period beginning after March 15, 2006.

     Pepco implemented EITF 04-13 on April 1, 2006. The implementation did not have a material impact on Pepco's overall financial condition, results of operations, or cash flows for the second quarter of 2006.

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     FSP FIN 46(R)-6, "Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)"

     In April 2006, the FASB issued FSP FIN 46(R)-6, "Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R), (FSP FIN 46(R)-6)" which provides guidance on how to determine the variability to be considered in applying FIN 46(R), "Consolidation of Variable Interest Entities."

     The guidance in FSP FIN 46(R)-6 is applicable prospectively beginning the first day of the first reporting period beginning after June 15, 2006.

     Pepco started applying the guidance in FSP FIN 46(R)-6 to new and modified arrangements effective July 1, 2006.

     EITF Issue No. 06-3, "Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions"

     On June 28, 2006, the FASB ratified EITF Issue No. 06-3, "Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions" (EITF 06-3). EITF 06-3 provides guidance on an entity's disclosure of its accounting policy regarding the gross or net presentation of certain taxes and provides that if taxes included in gross revenues are significant, a company should disclose the amount of such taxes for each period for which an income statement is presented (i.e., both interim and annual periods). Taxes within the scope of EITF 06-3 are those that are imposed on and concurrent with a specific revenue-producing transaction. Taxes assessed on an entity's activities over a period of time are not within the scope of EITF 06-3. EITF 06-3 is effective for interim and annual reporting periods beginning after December 15, 2006 (March 31, 2007 for Pepco) although earlier application is permitted.

      Pepco does not anticipate that the adoption of EITF 06-3 will materially impact its disclosure requirements.

     FIN 48, "Accounting for Uncertainty in Income Taxes"

     On July 13, 2006, the FASB issued FIN 48, "Accounting for Uncertainty in Income Taxes" (FIN 48). FIN 48 clarifies the criteria for recognition of tax benefits in accordance with SFAS No. 109, "Accounting for Income Taxes," and prescribes a financial statement recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Specifically, it clarifies that an entity's tax benefits must be "more likely than not" of being sustained prior to recording the related tax benefit in the financial statements. If the position drops below the "more likely than not" standard, the benefit can no longer be recognized. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.

     FIN 48 is effective the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for Pepco). Pepco is in the process of evaluating the impact of FIN 48, but does not believe it will have a material impact on its financial condition, results of operations, and cash flow.

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     SFAS No. 157, "Fair Value Measurements"

     In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" (SFAS No. 157) which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of this Statement will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements.

     SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (year ending December 31, 2008 for Pepco).

     Pepco is currently in the process of evaluating the impact of SFAS No. 157 on its financial condition, results of operations and cash flows.

     "Staff Accounting Bulletin No. 108"

     On September 13, 2006, the SEC issued SAB No. 108 (SAB 108) which expresses the SEC staff's views on the process of quantifying financial statement misstatements. SAB 108 requires that registrants quantify the impact of correcting all misstatements, including both the carryover and reversing effects of prior year misstatements, on the current year financial statements by quantifying an error using both the rollover and iron curtain approaches and by evaluating the error measured under each approach. Under SAB 108, a registrant's financial statements would require adjustment when either approach results in a material misstatement, after considering all relevant quantitative and qualitative factors. Further, the SEC believes that a registrant's materiality assessment of an identified unadjusted error should quantify the effects of the identified unadjusted error on each financial statement and related financial statement disclosure. SAB 108 is effective for fiscal years endi ng on or after November 15, 2006.

     Pepco implemented the guidance provided in SAB 108 during the year ended December 31, 2006.

     EITF Issue No. 06-5, "Accounting for Purchases of Life Insurance -- Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of Life Insurance

     On September 20, 2006, the FASB ratified EITF Issue No. 06-5, "Accounting for Purchases of Life Insurance -- Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of Life Insurance" (EITF 06-5) which provides guidance on whether an entity should consider the contractual ability to surrender all of the individual-life policies (or certificates under a group life policy) together when determining the amount that could be realized in accordance with FTB 85-4, and whether a guarantee of the additional value associated with the group life policy affects that determination. EITF 06-5 provides that a policyholder should (i) determine the amount that could be realized under the insurance contract assuming the surrender of an individual-life by individual-life policy (or certificate by certificate in a group policy) and (ii) not discount the cash surrender value component of the amount that could be realized when c ontractual restrictions on the ability to surrender a policy exist unless contractual limitations prescribe that the cash surrender value component of the amount that could be realized is a fixed amount, in

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which case the amount that could be realized should be discounted in accordance with Opinion 21. EITF 06-5 is effective for fiscal years beginning after December 15, 2006 (year ending December 31, 2007 for Pepco).

     Pepco does not anticipate that the adoption of EITF 06-5 will materially impact its disclosure requirements.

     SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115"

     On February 15, 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115" (SFAS No. 159) which permits entities to choose to elect to measure eligible financial instruments at fair value. The objective of SFAS No. 159 is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of SFAS No. 159 will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements.

     SFAS No.159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company's choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. SFAS No. 159 does not eliminate disclosure requirements included in other accounting standards.

     SFAS No. 159 applies to fiscal years beginning after November 15, 2007 (year ending December 31, 2008 for Pepco), with early adoption permitted for an entity that has also elected to apply the provisions of SFAS No. 157, Fair Value Measurements.An entity is prohibited from retrospectively applying SFAS No. 159, unless it chooses early adoption. SFAS No. 159 also applies to eligible items existing at November 15, 2007 (or early adoption date). Pepco is in the process of evaluating the impact of SFAS No. 159 on its financial condition, results of operations and cash flows.

(3)  SEGMENT INFORMATION

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

(4)  LEASING ACTIVITIES

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

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semi-annual payments of $7.6 million over a 25-year period beginning in December 1994 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 expense charged on the obligation and amortization expense 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, 2006 and 2005 are comprised of the following:

At December 31, 2006	Original Cost	Accumulated Amortization	Net Book Value
	(Millions of dollars)
Transmission	$ 76.0	$18.0	$ 58.0
Distribution	76.0	18.0	58.0
Other	2.6	2.2	.4
Total	$154.6	$38.2	$116.4
At December 31, 2005
Transmission	$ 76.0	$15.7	$ 60.3
Distribution	76.0	15.7	60.3
Other	2.6	1.8	.8
Total	$154.6	$33.2	$121.4

(5)  PROPERTY, PLANT AND EQUIPMENT

     Property, plant and equipment is comprised of the following:

At December 31, 2006	Original Cost	Accumulated Depreciation	Net Book Value
	(Millions of dollars)
Distribution	$3,824.2	$1,587.6	$2,236.6
Transmission	722.7	312.1	410.6
Construction work in progress	174.0	-	174.0
Non-operating and other property	436.7	262.8	173.9
Total	$5,157.6	$2,162.5	$2,995.1
At December 31, 2005
Distribution	$3,659.5	$1,514.3	$2,145.2
Transmission	715.0	297.2	417.8
Construction work in progress	172.6	-	172.6
Non-operating and other property	442.9	256.5	186.4
Total	$4,990.0	$2,068.0	$2,922.0

     The non-operating and other property amounts include balances for general plant, distribution and transmission plant held for future use, intangible plant and non-utility property.

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Asset Sales

     In August 2005, Pepco sold for $75 million in cash 384,051 square feet of excess non-utility land owned by Pepco located at Buzzard Point in the District of Columbia. The sale resulted in a pre-tax gain of $68.1 million which was recorded as a reduction of Operating Expenses in the Statements of Earnings.

(6)  PENSIONS AND OTHER POSTRETIREMENT BENEFITS

     Pepco accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. For 2006, 2005, and 2004, Pepco's allocated share of the pension and other postretirement net periodic benefit cost incurred by Pepco Holdings was approximately $32.1 million, $28.9 million, and $24.1 million, respectively. In 2006 and 2005, Pepco made no contributions to the Retirement Plan, and $6.0 million and $3.1 million, respectively to other postretirement benefit plans.  At December 31, 2006 and 2005, Pepco's prepaid pension expense of $160.1 million and $161.3 million, and other postretirement benefit obligation of $69.3 million and $46.7 million, effectively represent assets and benefit obligations resulting from Pepco's participation in the Pepco Holdings benefit plan.

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(7)  LONG-TERM DEBT

     The components of long-term debt are shown below.

			At December 31,
Interest Rate	Maturity		2006		2005
			(Millions of dollars)
First Mortgage Bonds
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)(b)	2013		200.0		200.0
4.65% (a)(b)	2014		175.0		175.0
Variable (a)(b)	2022		109.5		-
6.00% (a)	2022		-		30.0
6.375% (a)	2023		-		37.0
5.375% (a)	2024		-		42.5
5.375% (a)	2024		38.3		38.3
5.75% (a)(b)	2034		100.0		100.0
5.40% (a)(b)	2035		175.0		175.0
Total First Mortgage Bonds			1,116.8		1,116.8
Medium-Term Notes
7.64%	2007		35.0		35.0
6.25%	2009		50.0		50.0
Notes (Unsecured)
Variable	2006		-		50.0
Total long-term debt			1,201.8		1,251.8
Net unamortized discount			(1.8)		(2.9)
Current maturities of long-term debt			(210.0)		(50.0)
Total net long-term debt		$	990.0	$	1,198.9

(a)

Represents a series of First Mortgage Bonds issued by Pepco as collateral for an outstanding series of senior notes ortax-exempt bonds issued by or for the benefit of Pepco. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or tax-exempt bonds are identical to the terms of the collateral First Mortgage Bonds by which it is secured. Payments of principal and interest on a series of senior notes or tax-exempt bonds satisfy the corresponding payment obligations on the related series of collateral First Mortgage Bonds. Because each series of senior notes and tax-exempt bonds and the series of collateral First Mortgage Bonds securing that series of senior notes or tax-exempt bonds effectively represents a single financial obligation, the senior notes and the tax-exempt bonds are not separately shown on the table.

(b)

Represents a series of First Mortgage Bonds issued by the indicated company as collateral for an outstanding series of senior notes that will, at such time as there are no First Mortgage Bonds of the issuing company outstanding (other than collateral First Mortgage Bonds securing payment of senior notes), cease to secure the corresponding series of senior notes and will be cancelled.

     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, 2006, that will mature in each of 2007 through 2011 and thereafter is as follows: $210 million in 2007, $128 million in 2008, $50 million in 2009, $16 million in 2010, zero in 2011, and $797.8 million thereafter.

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     Pepco's long-term debt is subject to certain covenants. Pepco is in compliance with all requirements.

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. Pepco had $67.1 million of short-term debt outstanding at December 31, 2006 and no short-term debt outstanding at December 31, 2005.

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 a $500 million credit facility, described below under the heading "Credit Facility," shared with Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE).

     Pepco had $67.1 million of commercial paper outstanding at December 31, 2006 and no commercial paper outstanding at December 31, 2005. The weighted average interest rate for commercial paper issued during 2006 was 5.25%. No commercial paper was issued during 2005. The weighted average maturity for commercial paper issued during 2006 was five days.

Credit Facility

     In April 2006, Pepco Holdings, Pepco, DPL and ACE extended their five-year credit agreement for one additional year from 2010 to 2011. The aggregate borrowing limit under the facility is $1.2 billion and the facility commitment expiration date is May 5, 2011. Pepco Holdings' credit limit under this agreement is $700 million.  The credit limit of each of Pepco, DPL and ACE is the lower of $300 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time under the agreement may not exceed $500 million. Under the terms of the credit agreement, the companies are entitled to request increases in the principal amount of available credit up to an aggregate increase of $300 million, with any such increase proportionately increasing the credit limit of each of the respective borrowers and the $300 million sublimits for each of Pepco, DPL a nd ACE.  The interest rate payable by the respective companies on utilized funds is determined by a pricing schedule with rates corresponding to the credit rating of the borrower. Any indebtedness incurred under the credit agreement would be unsecured.

     The credit agreement is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies also are permitted to use the facility to borrow funds for general corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties made by the borrower at the time the credit agreement was entered into also must be true at the time the facility is utilized, and the borrower must be in compliance with specified covenants, including the financial covenant described below. However, a material adverse change in the borrower's business, property, and results of operations or financial condition subsequent to the entry into

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the credit agreement is not a condition to the availability of credit under the facility. Among the covenants contained in the credit agreement are (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, (ii) a restriction on sales or other dispositions of assets, other than sales and dispositions permitted by the credit agreement, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than liens permitted by the credit agreement. The failure to satisfy any of the covenants or the occurrence of specified events that constitute an event of default could result in the acceleration of the repayment obligations of the borrower. The events of default include (i) the failure of any borrowing company or any of its significant subsidiaries to pay when due, or the acceleration of, certain indebtedness under other borrowing arrangements, (ii) certain bankruptcy events, judgments or decrees against any borrowing company or its significant subsidiaries, and (iii) a change in control (as defined in the credit agreement) of Pepco Holdings or the failure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE. The agreement does not include any ratings triggers. There were no balances outstanding at December 31, 2006 and 2005.

(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 that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company 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.

     The provision for income taxes, reconciliation of income tax expense, and components of deferred income tax liabilities (assets) are shown below.

Provision for Income Taxes

	For the Year Ended December 31,
		2006			2005			2004
		(Millions of dollars)
Current Tax Expense
Federal	$		13.0	$		142.1	$		19.2
State and local			8.4			36.7			12.6
Total Current Tax Expense			21.4			178.8			31.8
Deferred Tax Expense (Benefit)
Federal			36.0			(36.4)			27.5
State and local			2.0			(12.8)			(1.6)
Investment tax credits			(2.0)			(2.0)			(2.0)
Total Deferred Tax Expense (Benefit)			36.0			(51.2)			23.9
Total Income Tax Expense	$		57.4	$		127.6	$		55.7

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Reconciliation of Income Tax Expense

		For the Year Ended December 31,
		2006			2005			2004
		(Millions of dollars)
		Amount	Rate		Amount	Rate		Amount	Rate
Income Before Income Taxes	$	142.8		$	292.6		$	152.2
Income tax at federal statutory rate	$	50.0	.35	$	102.4	.35	$	53.3	.35
Increases (decreases) resulting from
Depreciation		5.9	.04		5.3	.02		5.9	.04
Asset removal costs		(3.1)	(.02)		(3.3)	(.01)		(1.7)	(.01)
State income taxes, net of       federal effect		6.9	.05		15.6	.05		8.0	.05
Software amortization		3.0	.02		5.2	.02		(3.6)	(.02)
Tax credits		(2.1)	(.02)		(2.3)	(.01)		(2.7)	(.02)
Change in estimates related to       prior year tax liabilities		(1.5)	(.01)		6.1	.02		(3.8)	(.02)
Other, net		(1.7)	(.01)		(1.4)	-		.3	-
Total Income Tax Expense	$	57.4	.40	$	127.6	.44	$	55.7	.37

Components of Deferred Income Tax Liabilities (Assets)

		At December 31,
	2006		2005
	(Millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other book to tax basis differences	$	725.1	$	673.7
Pension plan contribution		58.8		73.5
Other Post Employment Benefits		(33.5)		(24.3)
Deferred taxes on amounts to be collected through     future rates		(2.7)		4.2
Deferred investment tax credit		(12.6)		(13.4)
Contributions in aid of construction		(60.5)		(57.9)
Customer sharing		16.0		(.4)
Transition costs		(14.3)		(14.3)
Property taxes and other		(42.8)		(22.3)
Total Deferred Tax Liabilities, Net		633.5		618.8
Deferred tax assets included in   Other Current Assets		2.8		3.2
Total Deferred Tax Liabilities, Net - Non-Current	$	636.3	$	622.0

     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, 2006 and 2005.

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     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.

Taxes Other Than Income Taxes

     Taxes other than income taxes for each year are shown below. These amounts relate to the Power Delivery business and are recoverable through rates.

	2006	2005	2004
	(Millions of dollars)
Gross Receipts/Delivery	$108.7	$107.8	$103.6
Property	35.2	36.4	37.0
County Fuel and Energy	84.3	89.0	70.6
Environmental, Use and Other	44.9	42.9	37.8
Total	$273.1	$276.1	$249.0

(9)  PREFERRED STOCK

     The preferred stock amounts outstanding as of December 31, 2006 and 2005 are as follows.

Series	Redemption    Price	Shares Outstanding 2006           2005		December 31,   2006            2005
				(Millions of dollars)
Serial Preferred (1)
$2.44 Series of 1957	$51.00	-	216,846	$  -	$10.9
$2.46 Series of 1958	$51.00	-	99,789	-	5.0
$2.28 Series of 1965	$51.00	-	112,709	-	5.6
				$  -	$21.5

(1) In October 2005, Pepco redeemed 74,103 shares of its $2.46 Series 1958 Serial Preferred Stock, 13,148 shares of its $2.28 Series 1965 Serial Preferred Stock and 22,795 shares of its $2.44 Series 1957 Serial Preferred Stock for an aggregate redemption amount of $3.7 million, $.7 million and $1.1 million, respectively. On March 1, 2006, Pepco redeemed the remaining outstanding shares of each series of its Serial Preferred Stock, at 102% of par, for an aggregate redemption amount of $21.9 million.

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(10)FAIR VALUES OF FINANCIAL INSTRUMENTS

     The estimated fair values of Pepco's financial instruments at December 31, 2006 and 2005 are shown below.

		At December 31,
		2006			2005
		(Millions of dollars)
	Carrying  Amount		Fair Value	Carrying  Amount		Fair Value
Liabilities and Capitalization
Long-Term Debt		$990.0	$960.8		$1,198.9	$1,198.2
Serial Preferred Stock		$        -	$        -		$    21.5	$    18.2

     The methods and assumptions described below were used to estimate, at December 31, 2006 and 2005, the fair value of each class of financial instrument shown above for which it is practicable to estimate a value.

     The fair values of the Long-Term Debt, which include First Mortgage Bonds, Medium-Term Notes, and Unsecured 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 value of the Serial Preferred Stock, excluding amounts due within one year, was 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 generating assets to Mirant (formerly Southern Energy, Inc.). In July 2003, Mirant 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). On December 9, 2005, the Bankruptcy Court approved the Plan of Reorganization (the Reorganization Plan) of Mirant and the Mirant business emerged from bankruptcy on January 3, 2006, as a new corporation of the same name.

     As part of the bankruptcy proceeding, Mirant had been seeking to reject certain ongoing contractual arrangements under the Asset Purchase and Sale Agreement entered into by Pepco and Mirant for the sale of the generating assets that are described below. The Reorganization Plan did not resolve the issues relating to Mirant's efforts to reject these obligations nor did it resolve certain Pepco damage claims against the Mirant bankruptcy estate.

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     Power Purchase Agreement

     The Panda PPA obligates Pepco to purchase from Panda 230 megawatts of energy and capacity annually through 2021. At the time of the sale of Pepco's generating assets to Mirant, the purchase price of the energy and capacity under the Panda PPA was, and since that time has continued to be, substantially in excess of the 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 through 2021 to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the Panda PPA at a price equal to Pepco's purchase price from Panda (the PPA-Related Obligations).

     The SMECO Agreement

     Under the Asset Purchase and Sale Agreement, Pepco assigned to Mirant a Facility and Capacity Agreement entered into by Pepco with Southern Maryland Electric Cooperative, Inc. (SMECO), under which Pepco was obligated to purchase from SMECO the capacity of an 84-megawatt combustion turbine installed and owned by SMECO at a former Pepco generating facility at a cost of approximately $500,000 per month until 2015 (the SMECO Agreement). Pepco is responsible to SMECO for the performance of the SMECO Agreement if Mirant fails to perform its obligations thereunder.

     Settlement Agreements with Mirant

     On May 30, 2006, Pepco, PHI, and certain affiliated companies entered into the Settlement Agreement, which, subject to court approval, settles all outstanding issues between the parties arising from or related to the Mirant bankruptcy. Under the terms of the Settlement Agreement:

·	Mirant will assume the Asset Purchase and Sale Agreement, except for the PPA-Related Obligations, which Mirant will be permitted to reject.
·	Pepco will receive an allowed claim under the Reorganization Plan in an amount that will result in a total aggregate distribution to Pepco, net of certain transaction expenses, of $520 million, consisting of (i) $450 million in damages resulting from the rejection of the PPA-Related Obligations and (ii) $70 million in settlement of other Pepco damage claims against the Mirant bankruptcy estate (the Pepco Distribution).
·	Except as described below, the $520 million Pepco Distribution will be effected by means of the issuance to Pepco of shares of Mirant common stock (consisting of an initial distribution of 13.5 million shares of Mirant common stock, followed thereafter by a number of shares of Mirant common stock to be determined), which Pepco will be obligated to resell promptly in one or more block sale transactions. If the net proceeds that Pepco receives from the resale of the shares of Mirant common stock are less than $520 million, Pepco will receive a cash payment from Mirant equal to the difference, and if the net proceeds that Pepco receives from the resale of the shares of Mirant common stock are more than $520 million, Pepco will make a cash payment to Mirant equal to the difference.
·	If the closing price of shares of Mirant common stock is less than $16.00 per share for four business days in a twenty consecutive business day period, and Mirant has not made a distribution of shares of Mirant common stock to Pepco under the Settlement Agreement, Mirant has the one-time option to elect to assume, rather than reject, the
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	PPA-Related Obligations. If Mirant elects to assume the PPA-Related Obligations, the Pepco Distribution will be reduced to $70 million.
·	All pending appeals, adversary actions or other contested matters between Pepco and Mirant will be dismissed with prejudice, and each will release the other from any and all claims relating to the Mirant bankruptcy.

     Separately, Mirant and SMECO have entered into a Settlement Agreement and Release (the SMECO Settlement Agreement). The SMECO Settlement Agreement provides that Mirant will assume, rather than reject, the SMECO Agreement. This assumption ensures that Pepco will not incur liability to SMECO as the guarantor of the SMECO Agreement due to the rejection of the SMECO Agreement, although Pepco will continue to guarantee to SMECO the future performance of Mirant under the SMECO Agreement.

     According to their terms, the Settlement Agreement and the SMECO Settlement Agreement will become effective when the Bankruptcy Court or the United States District Court for the Northern District of Texas (the District Court), as applicable, has entered a final order, not subject to appeal or rehearing, approving both the Settlement Agreement and the SMECO Settlement Agreement.

     On August 9, 2006, the Bankruptcy Court issued an order approving the Settlement Agreement and the SMECO Settlement Agreement. On August 18, 2006, certain holders of Mirant bankruptcy claims, who had objected to approval of the Settlement Agreement and the SMECO Settlement Agreement before the Bankruptcy Court, appealed the approval order to the District Court. On December 26, 2006, the District Court issued an order affirming the Bankruptcy Court's order approving the Settlement Agreement. On January 25, 2007, the parties that previously appealed the Bankruptcy Court's order filed a notice of appeal of the District Court's order with the United States Court of Appeals for the Fifth Circuit (the Fifth Circuit). On February 12, 2007, the Fifth Circuit issued a briefing schedule. The brief of the appealing creditors is due on March 26, 2007, while Mirant's and Pepco's briefs are due on April 30, 2007.

     In August 2006, Mirant made a cash payment to Pepco of $70 million, which became due in accordance with the terms of the Settlement Agreement as a result of the approval of the Settlement Agreement by the Bankruptcy Court. If the Bankruptcy Court order approving the Settlement Agreement becomes a final order after the exhaustion of all appeals, the payment will be taken into account as if it were proceeds from the resale by Pepco of shares of the Mirant common stock, as described above, and treated as a portion of the $520 million payment due Pepco. If the Bankruptcy Court approval of the Settlement Agreement is not upheld on appeal, Pepco must repay this cash payment to Mirant. Therefore, no income statement impact has been recognized in relation to the $70 million payment.

     Until the approval of the Settlement Agreement and the SMECO Settlement Agreement becomes final, Mirant is required to continue to perform all of its contractual obligations to Pepco and SMECO. Pepco intends to use the $450 million portion of the Pepco Distribution related to the rejection of the PPA-Related Obligations to pay for future capacity and energy purchases under the Panda PPA.

     In litigation prior to the entry into the Settlement Agreement, the District Court had entered orders denying Mirant's attempt to reject the PPA-Related Obligations and directing Mirant to resume making payments to Pepco pursuant to the PPA-Related Obligations, which Mirant had

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suspended. Mirant is making the payments as required by the District Court order. On July 19, 2006, the Fifth Circuit issued an opinion affirming the District Court's orders. On September 4, 2006, Mirant filed a petition for rehearing and motion to stay the appeals pending completion of the settlement between the parties. On September 12, 2006, the Fifth Circuit issued an Order denying Mirant's motion for stay. On September 21, 2006, the Fifth Circuit issued an Order summarily denying Mirant's petition for rehearing. The appeal period has expired and that order is now final and nonappealable.

Rate Proceedings

     Pepco currently has active electric distribution base rate cases underway in the District of Columbia and Maryland. In each of these cases, Pepco has proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers. The BSA will increase rates if revenues from distribution deliveries fall below the level approved by the applicable regulatory commission and will decrease rates if revenues from distribution deliveries are above the commission-approved level. The end result will be that Pepco will collect its authorized revenues for distribution deliveries. As a consequence, a BSA "decouples" revenue from unit sales consumption and ties the growth in revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable utility distribution revenues that are better aligned with costs, (ii ) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers' delivery bills, and (iv) removes any disincentives for Pepco to promote energy efficiency programs for its customers, because it breaks the link between overall sales volumes and delivery revenues. Pepco proposed a quarterly BSA.

     District of Columbia

     In February 2006, Pepco filed an update to the District of Columbia GPC for the periods February 8, 2002 through February 7, 2004 and February 8, 2004 through February 7, 2005. The GPC provides for sharing of the profit from SOS sales. The update to the GPC in the District of Columbia takes into account the $112.4 million in proceeds received by Pepco from the December 2005 sale of an allowed bankruptcy claim against Mirant arising from a settlement agreement entered into with Mirant relating to Mirant's obligation to supply energy and capacity to fulfill Pepco's SOS obligations in the District of Columbia. The filing also incorporates true-ups to previous disbursements in the GPC for the District of Columbia. In the filing, Pepco requested that $24.3 million be credited to District of Columbia customers during the twelve-month period beginning April 2006. On June 15, 2006, the DCPSC granted conditional approval of the GPC update as filed, effective July 1, 2006. Final approval by the DCPSC is pending.

     On December 12, 2006, Pepco submitted an application to the DCPSC to increase electric distribution base rates, including a proposed BSA. The application requested an annual increase of approximately $46.2 million or an overall increase of 13.5%, reflecting a proposed ROE of 10.75%. If the BSA is not approved, the proposed annual increase would be $50.5 million or an overall increase of 14.8%, reflecting an ROE of 11.00%. The application also proposed a Pension/OPEB Expense Surcharge that will allow Pepco to reflect in its distribution rates the increases and decreases that occur in the level of its pension and other post-employment benefits expense. A DCPSC decision is expected in mid-September 2007.

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     Maryland

     On November 17, 2006, Pepco submitted an application to the MPSC to increase electric distribution base rates, including a proposed BSA. The application requested an annual increase of approximately $47.4 million or an overall increase of 10.9%, reflecting a proposed ROE of 11.00%. If the BSA is not approved, the proposed annual increase would be $55.7 million or an overall increase of 12.9%, reflecting a proposed ROE of 11.25%. The application also proposed a Pension/OPEB Expense Surcharge that would allow Pepco to reflect in its distribution rates the increases and decreases that occur in the level of its pension and other post-employment benefits expense. The application requested that rates go into effect on December 17, 2006. In an order dated December 11, 2006, the MPSC suspended the proposed rates pending MPSC approval. An MPSC decision is expected in June 2007.

     Federal Energy Regulatory Commission

     On May 15, 2006, Pepco updated its FERC-approved formula transmission rates based on its FERC Form 1 data for 2005. This new rate of $12,009 per megawatt per year became effective on June 1, 2006. By operation of the formula rate process, the new rate incorporates true-ups from the 2005 formula rate that was effective June 1, 2005 and the new 2005 customer demand or peak load. Also, beginning in January 2007, the new rates will be applied to 2006 customer demand data, replacing the 2005 demand data that is currently used. This demand component is driven by Pepco's prior year peak load. Further, the rate change will be positively impacted by changes to distribution rates based on the merger settlements in Maryland and the District of Columbia. The net earnings impact expected from the network transmission rate changes is estimated to be a reduction of approximately $2 million year over year (2005 to 2006).

Divestiture Cases

     District of Columbia

     Final briefs on Pepco's District of Columbia divestiture proceeds sharing application were filed with the DCPSC in July 2002 following an evidentiary hearing in June 2002. That application was filed to implement a provision of Pepco's DCPSC-approved divestiture settlement that provided for a sharing of any net proceeds from the sale of Pepco's generation-related assets. One of the principal issues in the case is whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code and its implementing regulations. As of December 31, 2006, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6.5 million and $5.8 million, respectively.

     Pepco believes that a sharing of EDIT and ADITC would violate the Internal Revenue Service (IRS) normalization rules. Under these rules, Pepco could not transfer the EDIT and the ADITC benefit to customers more quickly than on a straight line basis over the book life of the related assets. Since the assets are no longer owned there is no book life over which the EDIT and ADITC can be returned. If Pepco were required to share EDIT and ADITC and, as a result, the normalization rules were violated, Pepco would be unable to use accelerated depreciation on District of Columbia allocated or assigned property. In addition to sharing with customers the generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS an amount

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equal to Pepco's District of Columbia jurisdictional generation-related ADITC balance ($5.8 million as of December 31, 2006), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($4.7 million as of December 31, 2006) in each case as those balances exist as of the later of the date a DCPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the DCPSC order becomes operative.

     In March 2003, the IRS issued a notice of proposed rulemaking (NOPR), which would allow for the sharing of EDIT and ADITC related to divested assets with utility customers on a prospective basis and at the election of the taxpayer on a retroactive basis. In December 2005 a revised NOPR was issued which, among other things, withdrew the March 2003 NOPR and eliminated the taxpayer's ability to elect to apply the regulation retroactively. Comments on the revised NOPR were filed in March 2006, and a public hearing was held in April 2006. Pepco filed a letter with the DCPSC in January 2006, in which it has reiterated that the DCPSC should continue to defer any decision on the ADITC and EDIT issues until the IRS issues final regulations or states that its regulations project related to this issue will be terminated without the issuance of any regulations. Other issues in the divestiture proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.

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

     Maryland

    Pepco filed its divestiture proceeds plan application with the MPSC in April 2001. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that has been raised in the District of Columbia case. See the discussion above under "Divestiture Cases -- District of Columbia." As of December 31, 2006, the Maryland allocated portions of EDIT and ADITC associated with the divested generating 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 with respect to the application 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 (discussed abo ve) 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 ($9.1 million as of December 31, 2006), and the Maryland-allocated portion of generation-related ADITC. Furthermore, Pepco would have to pay to the IRS an amount equal to Pepco's Maryland jurisdictional generation-related ADITC balance ($10.4 million as of December 31, 2006), as well as its Maryland retail

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jurisdictional ADITC transmission and distribution-related balance ($8.4 million as of December 31, 2006), in each case as those balances exist 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. The Hearing Examiner decided all other issues in favor of Pepco, except for the determination that only one-half of the severance payments that Pepco included in its calculation of corporate reorganization costs should be deducted from the sales proceeds before sharing of the net gain between Pepco and customers. Pepco filed a letter with the MPSC in January 2006, in which it has reiterated that the MPSC should continue to defer any decision on the ADITC and EDIT issues until the IRS issues final regulations or states that its regulations project related to this issue will be terminated without the issuance of any regulations.

     In December 2003, Pepco appealed the Hearing Examiner's decision to the MPSC as it relates to the treatment of EDIT and ADITC and corporate reorganization costs. The MPSC has not issued any ruling on the appeal and Pepco does not believe that it will do so until action is taken by the IRS as described above. 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 in addition to the additional gain-sharing payments relating to the disallowed severance payments, which Pepco is not contesting. 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 mate rial adverse impact on its financial position or cash flows.

Default Electricity Supply Proceedings in Maryland

     Pursuant to an order issued by the MPSC in November 2006, Pepco is the SOS provider to its delivery customers who do not choose an alternative electricity supplier. Pepco purchases the power supply required to satisfy its SOS obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved and supervised by the MPSC. In March 2006, Pepco announced the results of competitive bids to supply electricity to its Maryland SOS customers for one year beginning June 1, 2006. Due to significant increases in the cost of fuels used to generate electricity, the auction results had the effect of increasing the average monthly electric bill by about 38.5% for Pepco's Maryland residential customers.

     On April 21, 2006, the MPSC approved a settlement agreement among Pepco, its affiliate DPL, the staff of the MPSC and the Office of Peoples Counsel of Maryland, which provides for a rate mitigation plan for the residential customers of Pepco. Under the plan, the full increase for Pepco's residential customers who affirmatively elect to participate are being phased-in in increments of 15% on June 1, 2006, 15.7% on March 1, 2007 and the remainder on June 1, 2007. Customers electing to participate in the rate deferral plan will be required to pay the deferred amounts over an 18-month period beginning June 1, 2007. Pepco will accrue the interest cost to fund the deferral program. The interest cost will be absorbed by Pepco during the period that the deferred balance is accumulated and collected from customers, to the extent of and offset against the margins that Pepco otherwise would earn for providing SOS to residential customers. As of December 31, 2006, approximately 2% o f Pepco's residential customers had elected to participate in the phase-in program.

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     On June 23, 2006, Maryland enacted legislation that extended the period for customers to elect to participate in the phase-in of higher rates and revised the obligation to provide SOS to residential and small commercial customers until further action of the General Assembly. The legislation also provides for a customer refund reflecting the difference between the interest expense on an initially projected deferred balance at a 25% customer participation level and the interest expense on a deferred balance based on actual participation levels referred to above. The total amount of the refund is approximately $1.1 million for Pepco customers. At Pepco's 2% level of participation, Pepco estimates that the deferral balance, net of taxes, will be approximately $1.4 million. In July 2006, the MPSC approved a revised tariff rider filed in June 2006 by Pepco to implement the legislation.

General Litigation

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

     Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed. As a result of two motions to dismiss, numerous hearings and meetings and one motion for summary judgment, Pepco has had approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of January 31, 2007, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland; of which 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. Under the terms of the Settlement Agreement, Mirant has agreed to assume this contractual obligation. For a description of the Settlement Agreement, see the discussion of the relationship with Mirant above.

     While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) exceeds $360 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 position, results of operations or cash flows. However, if an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco's financial position, results of operations or cash flows.

Environmental Litigation

     Pepco is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. Pepco may incur costs to clean up currently

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or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. Although penalties assessed for violations of environmental laws and regulations are not recoverable from Pepco's customers, environmental clean-up costs incurred by Pepco would be included in its cost of service for ratemaking purposes.

     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 a notified by the U.S. Environmental Protection Agency (EPA) that it, along with a number of other utilities and non-utilities, was a potentially responsible party (PRP) in connection with the PCB contamination at the site.

     In 1994, an RI/FS including a number of possible remedies was submitted to the EPA. In 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 1998, the EPA issued a unilateral administrative order to Pepco and 12 other PRPs directing them to conduct the design and actions called for in its decision. In May 2003, two of the potentially liable owner/operator entities filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. In October 2003, the bankruptcy court confirmed a reorganization plan that incorporates the terms of a settlement among the two debtor owner/operator entities, the United States and a group of utility PRPs including Pepco (the Utility PRPs). Under the bankruptcy settlement, the reorganized entity/site owner will pay a total of $13.25 million to remediate the site (the Bankruptcy Settlement).

     In March 2006, the United States District Court for the Eastern District of Pennsylvania approved global consent decrees for the Metal Bank/Cottman Avenue site, entered into on August 23, 2005, involving the Utility PRPs, the U.S. Department of Justice, EPA, The City of Philadelphia and two owner/operators of the site. Under the terms of the settlement, the two owner/operators will make payments totaling $5.55 million to the U.S. Department of Justice and totaling $4.05 million to the Utility PRPs. The Utility PRPs will perform the remedy at the site and will be able to draw on the $13.25 million from the Bankruptcy Settlement to accomplish the remediation (the Bankruptcy Funds). The Utility PRPs will contribute funds to the extent remediation costs exceed the Bankruptcy Funds available. The Utility PRPs also will be liable for EPA costs associated with overseeing the monitoring and operation of the site remedy after the remedy construction is certified to be complete and also the cost of performing the "5 year" review of site conditions required by the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Any Bankruptcy Funds not spent on the remedy may be used to cover the Utility PRPs' liabilities for future costs. No parties are released from potential liability for damages to natural resources.

     As of December 31, 2006, Pepco had accrued $1.7 million to meet its liability for a remedy at the Metal Bank/Cottman Avenue site. While final costs to Pepco of the settlement have not been determined, Pepco believes that its liability at this site will not have a material adverse effect on its financial position, results of operations or cash flows.

IRS Mixed Service Cost Issue

     During 2001, Pepco changed its method of accounting with respect to capitalizable construction costs for income tax purposes. The change allowed Pepco to accelerate the

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deduction of certain expenses that were previously capitalized and depreciated. Through December 31, 2005, these accelerated deductions generated incremental tax cash flow benefits of approximately $94 million, primarily attributable to its 2001 tax returns.

     On August 2, 2005, the Treasury Department released regulations that, if adopted in their current form, would require Pepco to change its method of accounting with respect to capitalizable construction costs for income tax purposes for tax periods beginning in 2005. Based on those regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believes will be acceptable to the IRS.

     On the same day that the new regulations were released, the IRS issued Revenue Ruling 2005-53, which is intended to limit the ability of certain taxpayers to utilize the method of accounting for income tax purposes they utilized on their tax returns for 2004 and prior years with respect to capitalizable construction costs. In line with this Revenue Ruling, the IRS revenue agent's report for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that Pepco had claimed on those returns by requiring it to capitalize and depreciate certain expenses rather than treat such expenses as current deductions. PHI's protest of the IRS adjustments is among the unresolved audit matters relating to the 2001 and 2002 audits pending before the Appeals Office.

     In February 2006, PHI paid approximately $121 million of taxes to cover the amount of taxes that management estimated to be payable based on the method of tax accounting that PHI, pursuant to the proposed regulations, has adopted on its 2005 tax return. However, if the IRS is successful in requiring Pepco to capitalize and depreciate construction costs that result in a tax and interest assessment greater than management's estimate of $121 million, PHI will be required to pay additional taxes and interest only to the extent these adjustments exceed the $121 million payment made in February 2006.

Contractual Obligations

     As of December 31, 2006, Pepco's contractual obligations under non-derivative fuel and power purchase contracts (excluding PPA-related obligations that are part of the back-to-back agreement with Mirant) were $810.3 million in 2007, $484.2 million in 2008 to 2009, $19.1 million in 2010 to 2011, and zero in 2012 and thereafter.

(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 by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to Pepco for the years ended December 31, 2006, 2005 and 2004 were approximately $114.4 million, $114.6 million and $91.1 million, respectively.

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     Certain subsidiaries of Pepco Energy Services perform utility maintenance services, including services that are treated as capital costs, for Pepco. Amounts paid by Pepco to these companies for the years ended December 31, 2006, 2005 and 2004 were approximately $15.3 million, $11.6 million and $14.1 million, respectively.

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

	For the Year Ended December 31,
	2006	2005	2004
Income (Expense)	(Millions of dollars)
Intercompany power purchases - Conectiv Energy Supply (a)	$(35.6)	$       -	$     -
Intercompany lease transactions (b)	$  (2.4)	$ (4.4)	$(5.6)

     As of December 31, 2006 and 2005, Pepco had the following balances on its Balance Sheets due (to)/from related parties:

	2006	2005
Asset (Liability)	(Millions of dollars)
Payable to Related Party (current)
PHI Service Company	$(.9)	$(15.3)
PHI Parent	(5.0)	(.1)
Conectiv Energy Supply	(4.8)	-
Pepco Energy Services (c)	(35.4)	(25.0)
The items listed above are included in the "Accounts payable to associated companies" balance on the Balance Sheet of $46.0 million and $40.3 million at December 31, 2006 and 2005, respectively.
Money Pool Balance with Pepco Holdings (included in cash and    cash equivalents in 2006 and 2005 on the Balance Sheet)	$    .4	$ 73.1

(a)	Included in fuel and purchased energy.
(b)	Included in other operation and maintenance.
(c)	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 and differences between summer and winter rates.

	2006
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Total
	(Millions of dollars)
Total Operating Revenue	$475.2	$520.5	$742.3	$478.5	$2,216.5
Total Operating Expenses	441.6	474.6	650.5	449.6	2,016.3
Operating Income	33.6	45.9	91.8	28.9	200.2
Other Expenses	(13.9)	(13.6)	(15.4)	(14.5)	(57.4)
Income Before Income Tax Expense	19.7	32.3	76.4	14.4	142.8
Income Tax Expense	9.1	13.4	27.5	7.4	57.4
Net Income	10.6	18.9	48.9	7.0	85.4
Dividends on Preferred Stock	1.0	-	-	-	1.0
Earnings Available for Common Stock	$  9.6	$  18.9	$  48.9	$   7.0	$    84.4

	2005
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Total
	(Millions of dollars)
Total Operating Revenue	$419.9	$403.5	$581.1	$440.8	$1,845.3
Total Operating Expenses	386.3	341.7	419.2 (a)	341.8 (b)	1,489.0
Operating Income	33.6	61.8	161.9	99.0	356.3
Other Expenses	(16.8)	(13.8)	(17.0)	(16.1)	(63.7)
Income Before Income Tax Expense	16.8	48.0	144.9	82.9	292.6
Income Tax Expense	7.7	20.3	64.1 (c)	35.5 (d)	127.6
Net Income	9.1	27.7	80.8	47.4	165.0
Dividends on Preferred Stock	.3	.3	.3	.4	1.3
Earnings Available for Common Stock	$  8.8	$ 27.4	$ 80.5	$ 47.0	$  163.7

NOTE:	Sales of electric energy are seasonal and, accordingly, comparisons by quarter within a year are not meaningful.
(a)	Includes $68.1 million gain ($40.7 million after-tax) from sale of non-utility land owned by Pepco at Buzzard Point.
(b)	Includes $70.5 million gain ($42.2 million after-tax) from the settlement of Pepco's $105 million allowed, pre-petition general unsecured claim against Mirant.
(c)	Includes $4.6 million in income tax expense related to the mixed service cost issue under IRS Ruling 2005-53.
(d)	Includes $1.4 million in income tax expense related to the mixed service cost issue under IRS Ruling 2005-53.

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Report of Independent Registered Public Accounting Firm

To the Shareholder and Board of Directors
of Delmarva Power & Light Company:

In our opinion, the 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.) at December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006 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 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 statement schedule based on our audits. We conducted our audits of these statements in acco rdance 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.

PricewaterhouseCoopers LLP
Washington, DC
March 1, 2007

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DELMARVA POWER & LIGHT COMPANY STATEMENTS OF EARNINGS
For the Year Ended December 31,	2006	2005	2004
(Millions of dollars)
Operating Revenue
Electric	$1,168.0	$1,082.3	$1,017.4
Natural Gas	255.4	261.5	228.6
Total Operating Revenue	1,423.4	1,343.8	1,246.0
Operating Expenses
Fuel and purchased energy	816.8	698.0	655.6
Gas purchased	198.4	196.8	163.7
Other operation and maintenance	184.9	180.1	177.0
Depreciation and amortization	76.7	75.7	73.9
Other taxes	36.6	34.4	35.3
Gain on sales of assets	(1.5)	(3.6)	-
Total Operating Expenses	1,311.9	1,181.4	1,105.5
Operating Income	111.5	162.4	140.5
Other Income (Expenses)
Interest and dividend income	1.2	.9	.4
Interest expense	(41.1)	(34.7)	(33.0)
Other income	7.3	8.3	7.6
Other expenses	(4.3)	(4.6)	(4.4)
Total Other Expenses	(36.9)	(30.1)	(29.4)
Income Before Income Tax Expense	74.6	132.3	111.1
Income Tax Expense	32.1	57.6	48.1
Net Income	42.5	74.7	63.0
Dividends on Redeemable Serial Preferred Stock	.8	1.0	1.0
Earnings Available for Common Stock	$   41.7	$   73.7	$   62.0
The accompanying Notes are an integral part of these Financial Statements.

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DELMARVA POWER & LIGHT COMPANY BALANCE SHEETS
ASSETS	December 31, 2006	December 31, 2005
(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents	$    8.2	$    7.4
Accounts receivable, less allowance for uncollectible      accounts of $7.8 million and $9.2 million, respectively	193.7	181.4
Fuel, materials and supplies - at average cost	40.1	41.8
Prepayments of income taxes	46.3	-
Prepaid expenses and other	18.4	28.4
Total Current Assets	306.7	259.0
INVESTMENTS AND OTHER ASSETS
Goodwill	48.5	48.5
Regulatory assets	187.2	140.9
Prepaid pension expense	171.8	213.3
Other	18.4	32.7
Total Investments and Other Assets	425.9	435.4
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	2,512.8	2,409.5
Accumulated depreciation	(794.2)	(800.3)
Net Property, Plant and Equipment	1,718.6	1,609.2
TOTAL ASSETS	$2,451.2	$2,303.6
The accompanying Notes are an integral part of these Financial Statements.

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DELMARVA POWER & LIGHT COMPANY BALANCE SHEETS
LIABILITIES AND SHAREHOLDER'S EQUITY	December 31, 2006	December 31, 2005
(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$  195.9	$  165.5
Current maturities of long-term debt	64.7	22.9
Accounts payable and accrued liabilities	95.0	74.0
Accounts payable due to associated companies	9.6	57.3
Capital lease obligations due within one year	-	.2
Taxes accrued	3.2	33.7
Interest accrued	6.2	6.4
Other	58.4	48.2
Total Current Liabilities	433.0	408.2
DEFERRED CREDITS
Regulatory liabilities	272.4	242.5
Income taxes	424.1	413.7
Investment tax credits	9.9	10.7
Above-market purchased energy contracts and other       electric restructuring liabilities	23.5	25.8
Other	49.2	33.0
Total Deferred Credits	779.1	725.7
LONG-TERM LIABILITIES
Long-term debt	551.8	516.4
Total Long-Term Liabilities	551.8	516.4
COMMITMENTS AND CONTINGENCIES (NOTE 11)
REDEEMABLE SERIAL PREFERRED STOCK	18.2	18.2
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	242.7	235.4
Retained earnings	426.4	399.7
Total Shareholder's Equity	669.1	635.1
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$2,451.2	$2,303.6
The accompanying Notes are an integral part of these Financial Statements.

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DELMARVA POWER & LIGHT COMPANY STATEMENTS OF CASH FLOWS
For the Year Ended December 31,	2006	2005		2004
(Millions of dollars)
OPERATING ACTIVITIES
Net income	$ 42.5		$ 74.7		$ 63.0
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	76.7		75.7		73.9
Gain on sale of assets	(1.5)		(3.6)		-
Deferred income taxes	38.8		(22.7)		66.5
Investment tax credit adjustments, net	(.9)		(.9)		(.9)
Prepaid pension expense	(6.6)		(8.6)		(9.3)
Energy supply contracts	(4.3)		(8.2)		(3.9)
Other deferred credits	(2.6)		1.1		.3
Other deferred charges	1.6		1.7		(.3)
Changes in:
Accounts receivable	(10.3)		(7.8)		(4.8)
Regulatory assets and liabilities	(31.4)		(1.1)		(9.1)
Fuel, materials and supplies	1.7		(3.4)		(4.2)
Accounts payable and accrued liabilities	10.2		28.3		9.8
Interest and taxes accrued	(75.4)		21.1		17.9
Prepaid expenses and other	3.1		(2.2)		1.0
Net Cash From Operating Activities	41.6		144.1		199.9
INVESTING ACTIVITIES
Investment in property, plant and equipment	(134.0)		(137.2)		(115.2)
Proceeds from/changes in:
Proceeds from sale of other assets	2.7		4.4		-
Changes in restricted cash	-		4.8		(4.8)
Net other investing activities	(1.6)		-		(1.1)
Net Cash Used By Investing Activities	(132.9)		(128.0)		(121.1)
FINANCING ACTIVITIES
Dividends paid to Pepco Holdings	(15.0)		(36.4)		(68.0)
Dividends paid on preferred stock	(.8)		(1.0)		(1.0)
Redemption of preferred stock	-		(3.5)		-
Redemption of debentures issued to financing trust	-		-		(70.0)
Issuances of long-term debt	100.0		100.0		100.0
Redemptions of long-term debt	(22.9)		(102.7)		(7.0)
Issuances (repayments) of short-term debt, net	30.4		31.2		(33.2)
Net other financing activities	.4		.1		(.8)
Net Cash From (Used By) Financing Activities	92.1		(12.3)		(80.0)
Net Increase (Decrease) In Cash and Cash Equivalents	.8		3.8		(1.2)
Cash and Cash Equivalents at Beginning of Year	7.4		3.6		4.8
CASH AND CASH EQUIVALENTS AT END OF YEAR	$  8.2		$  7.4		$  3.6
NONCASH ACTIVITIES
Asset retirement obligations associated with removal costs     transferred to regulatory liabilities	$ 50.3		$   2.4		$ (4.6)
Capital contribution in respect of     certain intercompany transactions	$  7.3		$      -		$ 21.9
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $.6 million,     $.9 million, and $.3 million, respectively), and paid (received)     for income taxes:
Interest	$ 38.7		$ 32.2		$  29.3
Income taxes	$ 32.6		$ 55.6		$(15.0)
The accompanying Notes are an integral part of these Financial Statements.

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DELMARVA POWER & LIGHT COMPANY STATEMENTS OF SHAREHOLDER'S EQUITY
	Common Stock		Premium on Stock	Capital Stock Expense	Retained Earnings
	Shares	Par Value
(Millions of dollars, except shares)
BALANCE, DECEMBER 31, 2003	1,000	$-	$223.5	$(10.0)	$368.4
Net Income	-	-	-	-	63.0
Capital contribution	-	-	21.9	-	-
Dividends:
Preferred stock	-	-	-	-	(1.0)
Common stock	-	-	-	-	(68.0)
BALANCE, DECEMBER 31, 2004	1,000	$-	$245.4	$(10.0)	$362.4
Net Income	-	-	-	-	74.7
Dividends:
Preferred stock	-	-	-	-	(1.0)
Common stock	-	-	-	-	(36.4)
BALANCE, DECEMBER 31, 2005	1,000	$-	$245.4	$(10.0)	$399.7
Net Income	-	-	-	-	42.5
Capital contributions	-	-	7.3	-	-
Dividends:					-
Preferred stock	-	-	-	-	(.8)
Common stock	-	-	-	-	(15.0)
BALANCE, DECEMBER 31, 2006	1,000	$-	$252.7	$(10.0)	$426.4
The accompanying Notes are an integral part of these Financial Statements.

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NOTES TO FINANCIAL STATEMENTS

DELMARVA POWER & LIGHT COMPANY

(1)  ORGANIZATION

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

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

     In this Form 10-K, DPL also refers to these supply service obligations generally as Default Electricity Supply.

     DPL is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI). Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between PHI and DPL and certain activities of DPL are subject to the regulatory oversight of the Federal Energy Regulatory Commission (FERC) under PUHCA 2005.

(2)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP), such as compliance with 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 financial statements and accompanying notes. Examples of significant estimates used by DPL include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, fair value calculations (based on estimated market pricing) associated with derivative instruments, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, and income tax provisions and reserves. Additionally, DPL is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. DPL records an estimated liability for these proceedings and claims based upon the probable and reasonably estimable criteria contained in Statement of Financial Accounting Standards (SFAS) No. 5, "Accounting for Contingencies." Although DPL believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

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Change in Accounting Estimates

     During 2005, DPL recorded the impact of a reduction in estimated unbilled revenue, primarily reflecting an increase in the estimated amount of power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). This change in accounting estimate reduced net earnings for the year ended December 31, 2005 by approximately $1.0 million.

Revenue Recognition

     DPL recognizes revenues for the supply and delivery of electricity and gas upon delivery to its customers, including amounts for services rendered, but not yet billed (unbilled revenue). DPL recorded amounts for unbilled revenue of $58.4 million and $63.5 million as of December 31, 2006 and 2005, respectively. These amounts are included in the "accounts receivable" line item in the accompanying Balance Sheets. DPL calculates unbilled revenue using an output based methodology. This methodology is based on the supply of electricity or gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix and estimated power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers), which are inherently uncertain and susceptible to change from period to period, the impact of which could be material. Si milarly, revenues from other 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 "Natural Gas" revenues, respectively. The taxes related to the consumption of electricity and gas by its customers, such as fuel, energy, or other similar taxes, are components of DPL's tariffs and, as such, are billed to customers and recorded in Operating Revenues. Accruals for these taxes by DPL are recorded in Other Taxes. Excise tax related generally to the consumption of gasoline by DPL 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 DPL's utility businesses are subject to regulation by the Delaware Public Service Commission (DPSC), the Maryland Public Service Commission (MPSC), and the Virginia State Corporation Commission (VSCC), and its wholesale operations are subject to regulation by FERC. DPL's natural gas transmission practices are regulated by the U.S. Department of Transportation.

     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 SFAS 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 must be charged to earnings.

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     The components of DPL's regulatory asset balances at December 31, 2006 and 2005 are as follows:

	2006	2005
	(Millions of dollars)
Deferred energy supply costs	$    6.9	$  18.3
Deferred recoverable income taxes	77.5	80.7
Deferred debt extinguishment costs	18.9	20.6
Unrecovered purchased power contract costs	2.4	6.0
Phase in credits	29.7	-
Other	51.8	15.3
Total regulatory assets	$187.2	$140.9

     The components of DPL's regulatory liability balances at December 31, 2006 and 2005 are as follows:

	2006	2005
(Millions of dollars)
Deferred income taxes due to customers	$  39.4	$  39.7
Accrued asset removal costs	229.5	179.2
Other	3.5	23.6
Total regulatory liabilities	$272.4	$242.5

     A description for each category of regulatory assets and regulatory liabilities follows:

     Deferred Energy Supply Costs: Primarily represents 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 a receivable from our customers for tax benefits DPL has previously flowed through before the company was ordered to provide deferred income taxes. As the temporary differences between the financial statement and tax basis of assets reverse, the deferred recoverable balances are reversed. 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 Contract Costs: Represents deferred costs related to purchase power contracts at DPL, which are being recovered from February 1996 through October 2007 and which earn a return.

     Phase In Credits: Represents a phase in credit for Maryland and Delaware customers to mitigate the immediate impact of the significant rate increases. The deferral period for Delaware is May 1, 2006 - January 1, 2008. It is recoverable over a 17-month period beginning January 1, 2008. It will be amortized over a straight-line basis. Delaware customers are all in the plan unless they "opt out." For Maryland, the deferral period is June 1, 2006 - June 1, 2007. The recovery period is over an 18-month period beginning June 2007. Customers for Maryland are

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required to "opt in." Recovery is the rate per kilowatt hour, based on usage during the recovery period. There is no return on these deferrals.

     Other: Includes losses associated with DPL's natural gas hedging activity and under-recovery of procurement, transmission and administration costs associated with Maryland and Delaware SOS. Increase in Other went from $15.3 million in 2005 to $51.8 million in 2006 primarily due to the gas hedging activity.

     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.

     Accrued Asset Removal Costs: Represents DPL's asset retirement obligation associated with removal costs accrued using public service commission approved depreciation rates for transmission, distribution and general utility property.

     Other: Includes gains associated with DPL's natural gas hedging activity and over-recovery of procurement, transmission and administration costs associated with Maryland and Delaware SOS.

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 amounts, determined on a separate return basis.

     The 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 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 Balance Sheets. For additional information, see the discussion under "Regulation of Power Delivery Operations," 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 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

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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 related to hedging activities, are fully recoverable through the fuel adjustment clause approved by the DPSC, and are deferred under Statement of Financial Accounting Standards (SFAS) No. 71 until recovered. At December 31, 2006, there was a net deferred derivative payable of $27.3 million, offset by a $28.5 million regulatory asset. At December 31, 2005, there was a deferred derivative receivable on DPL's balance sheet of $21.6 million, offset by a $21.6 million regulatory liability.

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 after the receivable is recorded). DPL 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. 71, utilities can capitalize as Allowance for Funds Used During Construction (AFUDC) the capital costs of financing the construction of plant and equipment. The debt portion of AFUDC is recorded as a reduction of "interest expense" and the equity portion of AFUDC is credited to "other income" in the accompanying Statements of Earnings.

     DPL recorded AFUDC for borrowed funds of $.6 million, $.9 million, and $.3 million for the years ended December 31, 2006, 2005, and 2004, respectively.

     DPL recorded amounts for the equity component of AFUDC of $.6 million, $.5 million and $.4 million for the years ended December 31, 2006, 2005 and 2004, respectively.

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. DPL's goodwill balance at December 31, 2006 and 2005 of $48.5 million was derived from DPL's acquisition of Conowingo Power Company in 1995. 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 at least annually.

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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 2006, DPL tested its goodwill for impairment as of July 1, 2006. This test 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, 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 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 be recognized only 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 Postretirement Benefit Plans

     Pepco Holdings sponsors a retirement plan that covers substantially all employees of DPL (the PHI Retirement Plan) and certain employees of other Pepco Holdings subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.

     The PHI Retirement Plan is accounted for in accordance with SFAS No. 87, "Employers' Accounting for Pensions," and its other postretirement benefits in accordance with SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." Pepco Holdings' financial statement disclosures were prepared in accordance with SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits."

     SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R)"

     In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R)" (SFAS No. 158). SFAS No. 158 requires that companies recognize a net liability or asset to report the funded status of their defined benefit pension and other postretirement benefit plans on the balance sheet. Recognizing the funded status of the company's benefit plans as a net liability or asset will

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require an offsetting adjustment to accumulated other comprehensive income in shareholders' equity or will be deferred as a regulatory asset or liability if probable of recovery in rates under SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS No. 158 does not change how pension and other postretirement benefits are accounted for and reported in the income statement.

     DPL participates in benefit plans sponsored by Pepco Holdings and as such, the provisions of SFAS No. 158 do not have an impact on its financial condition and cash flows.

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, see the "Asset Retirement Obligations" section included in this Note.

     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. The system-wide composite depreciation rates for 2006, 2005 and 2004 for DPL's transmission and distribution system property were approximately 3.0%, 3.1%, and 3.1%, respectively.

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 DPL and certain other PHI 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

     In accordance with SFAS No. 143, "Accounting for Asset Retirement Obligations" and Financial Accounting Standards Board Interpretation No. 47, asset removal costs are recorded as regulatory liabilities. At December 31, 2006 and 2005, $229.5 million and $179.2 million, respectively, are reflected as regulatory liabilities in the accompanying Balance Sheets. Additionally, in 2005, DPL recorded immaterial conditional asset retirement obligations for underground storage tanks. Accretion for these asset retirement obligations has been recorded as a regulatory asset.

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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 liabilities balance principally consists of customer deposits and accrued vacation liability.

Other Deferred Credits

     The other deferred credits balance principally consists of miscellaneous deferred liabilities.

Dividend Restrictions

     In addition to its future financial performance, the ability of DPL 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, may require the prior approval of DPL's utility regulatory commissions before dividends can be paid and (ii) the prior rights of holders of existing and future preferred stock, mortgage bonds and other long-term debt issued by DPL and any other restrictions imposed in connection with the incurrence of liabilities. DPL had approximately $113.3 million and $74.6 million of restricted retained earnings at December 31, 2006 and 2005, respectively.

Reclassifications

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

New Accounting Standards

     EITF 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

     In September 2005, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty" (EITF 04-13), which addresses circumstances under which two or more exchange transactions involving inventory with the same counterparty should be viewed as a single exchange transaction for the purposes of evaluating the effect of Accounting Principles Board Opinion 29, "Accounting for Nonmonetary Transactions." EITF 04-13 is effective for new arrangements entered into, or modifications or renewals of existing arrangements, beginning in the first interim or annual reporting period beginning after March 15, 2006.

     DPL implemented EITF 04-13 on April 1, 2006. The implementation did not have a material impact on DPL's overall financial condition, results of operations, or cash flows for the second quarter of 2006.

     FSP FIN 46(R)-6, "Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)"

     In April 2006, the FASB issued FSP FASB Interpretation Number (FIN) 46(R)-6, "Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R),

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(FSP FIN 46(R)-6)" which provides guidance on how to determine the variability to be considered in applying FIN 46(R), "Consolidation of Variable Interest Entities."

     The guidance in FSP FIN 46(R)-6 is applicable prospectively beginning the first day of the first reporting period beginning after June 15, 2006.

     DPL started applying the guidance in FSP FIN 46(R)-6 to new and modified arrangements effective July 1, 2006.

     EITF Issue No. 06-3, "Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions"

     On June 28, 2006, the FASB ratified EITF Issue No. 06-3, "Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions" (EITF 06-3). EITF 06-3 provides guidance on an entity's disclosure of its accounting policy regarding the gross or net presentation of certain taxes and provides that if taxes included in gross revenues are significant, a company should disclose the amount of such taxes for each period for which an income statement is presented (i.e., both interim and annual periods). Taxes within the scope of EITF 06-3 are those that are imposed on and concurrent with a specific revenue-producing transaction. Taxes assessed on an entity's activities over a period of time are not within the scope of EITF 06-3. EITF 06-3 is effective for interim and annual reporting periods beginning after December 15, 2006 (March 31, 2007 for DPL) although earlier application is permitted.

     DPL does not anticipate that the adoption of EITF 06-3 will materially impact its disclosure requirements.

     FIN 48, "Accounting for Uncertainty in Income Taxes"

     On July 13, 2006, the FASB issued FIN 48, "Accounting for Uncertainty in Income Taxes" (FIN 48). FIN 48 clarifies the criteria for recognition of tax benefits in accordance with SFAS No. 109, "Accounting for Income Taxes," and prescribes a financial statement recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Specifically, it clarifies that an entity's tax benefits must be "more likely than not" of being sustained prior to recording the related tax benefit in the financial statements. If the position drops below the "more likely than not" standard, the benefit can no longer be recognized. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.

     FIN 48 is effective the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for DPL). DPL is in the process of evaluating the impact of FIN 48, but does not believe it will have a material impact on its financial condition, results of operations, and cash flow.

     SFAS No. 157, "Fair Value Measurements"

     In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" (SFAS No. 157) which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of this Statement

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will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements.

     SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (year ending December 31, 2008 for DPL).

     DPL is currently in the process of evaluating the impact of SFAS No. 157 on its financial condition, results of operations and cash flows.

     "Staff Accounting Bulletin No. 108"

     On September 13, 2006, the SEC issued SAB No. 108 (SAB 108) which expresses the SEC staff's views on the process of quantifying financial statement misstatements. SAB 108 requires that registrants quantify the impact of correcting all misstatements, including both the carryover and reversing effects of prior year misstatements, on the current year financial statements by quantifying an error using both the rollover and iron curtain approaches and by evaluating the error measured under each approach. Under SAB 108, a registrant's financial statements would require adjustment when either approach results in a material misstatement, after considering all relevant quantitative and qualitative factors. Further, the SEC believes that a registrant's materiality assessment of an identified unadjusted error should quantify the effects of the identified unadjusted error on each financial statement and related financial statement disclosure. SAB 108 is effective for fiscal years endi ng on or after November 15, 2006.

     DPL implemented the guidance provided in SAB 108 during the year ended December 31, 2006.

     SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115"

     On February 15, 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115" (SFAS No. 159) which permits entities to choose to elect to measure eligible financial instruments at fair value. The objective of SFAS No. 159 is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of SFAS No. 159 will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements.

     SFAS No.159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company's choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. SFAS No. 159 does not eliminate disclosure requirements included in other accounting standards.

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     SFAS No. 159 applies to fiscal years beginning after November 15, 2007 (year ending December 31, 2008 for DPL), with early adoption permitted for an entity that has also elected to apply the provisions of SFAS No. 157, Fair Value Measurements.An entity is prohibited from retrospectively applying SFAS No. 159, unless it chooses early adoption. SFAS No. 159 also applies to eligible items existing at November 15, 2007 (or early adoption date). DPL is in the process of evaluating the impact of SFAS No. 159 on its financial condition, results of operations and cash flows.

(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 $114.8 million in the aggregate. DPL also has long-term leases for certain other facilities and equipment. Minimum commitments as of December 31, 2006, under the Merrill Creek Reservoir lease and other lease agreements, are as follows: 2007-$7.8 million; 2008-$8.6 million; 2009-$8.6 million; 2010-$8.5 million; 2011-$8.5 million; beyond 2011-$96.9 million; total-$138.9 million.

(5)  PROPERTY, PLANT AND EQUIPMENT

     Property, plant and equipment is comprised of the following:

At December 31, 2006	Original   Cost	Accumulated Depreciation	Net       Book Value
	(Millions of dollars)
Distribution	$1,273.3	$374.3	$  899.0
Transmission	610.9	196.6	414.3
Gas	349.8	97.6	252.2
Construction work in progress	67.2	-	67.2
Non-operating and other property	211.6	125.7	85.9
Total	$2,512.8	$794.2	$1,718.6
At December 31, 2005
Distribution	$1,236.0	$392.1	$  843.9
Transmission	524.1	194.9	329.2
Gas	339.5	100.7	238.8
Construction work in progress	101.1	-	101.1
Non-operating and other property	208.8	112.6	96.2
Total	$2,409.5	$800.3	$1,609.2

     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 POSTRETIREMENT BENEFITS

     DPL accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. For 2006, 2005, and 2004, DPL's allocated share of the pension and other

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postretirement net periodic benefit cost incurred by Pepco Holdings was approximately $.7 million, $(2.0) million, and $1.0 million, respectively. In 2006 and 2005, DPL contributed $6.8 million and $6.0 million, respectively to other postretirement benefit plans.  At December 31, 2006 and 2005, DPL's prepaid pension expense of $171.8 million and $213.3 million, and other postretirement benefit obligation, included in Other Assets, of $3.3 million and $10.1 million, effectively represent assets and benefit obligations resulting from DPL's participation in the Pepco Holdings benefit plan.

(7)  LONG-TERM DEBT

     Long-term debt outstanding as of December 31, 2006 and 2005 is presented below:

Type of Debt	Interest Rates	Maturity	2006	2005
			(Millions of dollars)
Amortizing First Mortgage Bonds	6.95%	2006-2008	$    7.6	$  10.5
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):
	6.75%	2006	-	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
			101.5	121.5
Notes (unsecured):
	5.00%	2014	100.0	100.0
	5.00%	2015	100.0	100.0
	5.22%	2016	100.0	-
			300.0	200.0
Total long-term debt			617.4	540.3
Unamortized premium and discount, net			(.9)	(1.0)
Current maturities of long-term debt			(64.7)	(22.9)
Total net long-term debt			$551.8	$516.4

(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.

     The outstanding First Mortgage Bonds issued by DPL are secured by a lien on substantially all of DPL's property, plant and equipment.

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     Maturities of long-term debt and sinking fund requirements during the next five years are as follows: 2007-$64.7 million; 2008-$22.6 million; 2009-zero; 2010-$31.2 million; 2011-$34.5 million; and $464.4 million thereafter.

     DPL's long-term debt is subject to certain covenants. DPL is in compliance with all requirements.

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, 2006 and 2005 is as follows.

	2006	2005
	(Millions of dollars)
Commercial paper	$91.1	$       -
Intercompany borrowings	-	60.7
Variable rate demand bonds	104.8	104.8
Total	$195.9	$165.5

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 a $500 million credit facility, described below under the heading "Credit Facility," shared with Potomac Electric Power Company (Pepco) and Atlantic City Electric Company (ACE).

     DPL had $91.1 million of commercial paper outstanding at December 31, 2006 and no commercial paper outstanding at December 31, 2005. The interest rate for commercial paper issued during 2006 was 5.3%. The weighted average maturity for commercial paper issued during 2006 was seven days.

Variable Rate Demand Bonds

     Variable Rate Demand Bonds ("VRDB") are subject to repayment on the demand of the holders and for this reason are accounted for as short-term debt in accordance with GAAP. 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 the credit worthiness of the company and because the remarketing agent resets the interest rate to the then-current market rate. The company also may utilize one of the fixed rate/fixed term conversion options of the bonds to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, DPL views VRDB as a source of long-term financing. The VRDB outstanding in 2006 and 2005 mature in 2017 ($26.0 million), 2024 ($33.3 million), 2028 ($15.5 million), and 2029 ($30.0 million). The weighted average interest rate for VRDB was 3.64% during 2006 and 2.63% during 2005. Of the $104.8 in VRDB, $71.5 is collateralized with first mortgage bonds.

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Credit Facility

     In April 2006, Pepco Holdings, Pepco, DPL and ACE extended their five-year credit agreement for one additional year from 2010 to 2011. The aggregate borrowing limit under the facility is $1.2 billion and the facility commitment expiration date is May 5, 2011. Pepco Holdings' credit limit under this agreement is $700 million.  The credit limit of each of Pepco, DPL and ACE is the lower of $300 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time under the agreement may not exceed $500 million. Under the terms of the credit agreement, the companies are entitled to request increases in the principal amount of available credit up to an aggregate increase of $300 million, with any such increase proportionately increasing the credit limit of each of the respective borrowers and the $300 million sublimits for each of Pepco, DPL a nd ACE.  The interest rate payable by the respective companies on utilized funds is determined by a pricing schedule with rates corresponding to the credit rating of the borrower. Any indebtedness incurred under the credit agreement would be unsecured.

     The credit agreement is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies also are permitted to use the facility to borrow funds for general corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties made by the borrower at the time the credit agreement was entered into also must be true at the time the facility is utilized, and the borrower must be in compliance with specified covenants, including the financial covenant described below. However, a material adverse change in the borrower's business, property, and results of operations or financial condition subsequent to the entry into the credit agreement is not a condition to the availability of credit under the facility. Among the covenants contained in the credit agreement are (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, (ii) a restriction on sales or other dispositions of assets, other than sales and dispositions permitted by the credit agreement, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than liens permitted by the credit agreement. The failure to satisfy any of the covenants or the occurrence of specified events that constitute an event of default could result in the acceleration of the repayment obligations of the borrower. The events of default include (i) the failure of any borrowing company or any of its significant subsidiaries to pay when due, or the acceleration of, certain indebtedness under other borrowing arrangements, (ii) certain bankruptcy events, judgments or decrees against any borrowing company or its significant subsidiaries, and (iii) a change in control (as defined in the credit agreement) of Pepco Holdings or the failure o f Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE. The agreement does not include any ratings triggers. There were no balances outstanding at December 31, 2006 and 2005.

(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 that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company 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.

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     The provision for income taxes, reconciliation of income tax expense, and components of deferred income tax liabilities (assets) are shown below.

Provision for Income Taxes

	For the Year Ended December 31,
	2006	2005	2004
	(Millions of dollars)
Current Tax (Benefit) Expense
Federal	$(4.4)	$64.3	$(16.0)
State and local	(1.3)	16.4	(1.4)
Total Current Tax (Benefit) Expense	(5.7)	80.7	(17.4)
Deferred Tax Expense (Benefit)
Federal	30.0	(16.3)	54.7
State and local	8.7	(5.9)	11.7
Investment tax credit amortization	(.9)	(.9)	(.9)
Total Deferred Tax Expense (Benefit)	37.8	(23.1)	65.5
Total Income Tax Expense	$32.1	$57.6	$48.1

Reconciliation of Income Tax Expense

		For the Year Ended December 31,
		2006			2005			2004
		(Millions of dollars)
		Amount	Rate		Amount	Rate		Amount	Rate
Income Before Income Taxes	$	74.6		$	132.3		$	111.1
Income tax at federal statutory rate	$	26.1	.35	$	46.3	.35	$	38.9	.35
Increases (decreases) resulting from
Depreciation		1.8	.02		2.0	.01		1.5	.01
State income taxes, net of       federal effect		4.8	.06		6.0	.05		6.5	.06
Tax credits		(.9)	(.01)		(.9)	(.01)		(.9)	(.01)
Change in estimates related to       prior year tax liabilities		.6	.01		4.3	.03		5.0	.04
Other, net		(.3)	-		(.1)	-		(2.9)	(.02)
Total Income Tax Expense	$	32.1	.43	$	57.6	.43	$	48.1	.43

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Components of Deferred Income Tax Liabilities (Assets)

	As of December 31,
	2006	2005
	(Millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other book to tax basis differences	$323.7	$298.8
Deferred recoverable income taxes	39.4	39.7
Prepaid pension expense	67.4	83.8
Tax credits	(3.8)	(4.1)
Above-market purchased energy contracts     and other Electric restructuring liabilities	(10.7)	(12.7)
Other	2.6	1.8
Total Deferred Tax Liabilities, net	418.6	407.3
Deferred tax assets included in Other Current Assets	5.5	6.4
Total Deferred Tax Liabilities, net - non-current	$424.1	$413.7

     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 DPL'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, 2006 and 2005.

     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 DPL's property continues to be normalized over the remaining service lives of the related assets.

Taxes Other Than Income Taxes

     Taxes other than income taxes for each year are shown below. These amounts relate to the Power Delivery business and are recoverable through rates.

	2006	2005	2004
	(Millions of dollars)
Gross Receipts/Delivery	$18.9	$18.9	$15.5
Property	17.1	15.1	16.0
Environmental, Use and Other	.6	.4	3.8
Total	$36.6	$34.4	$35.3

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(9)  PREFERRED STOCK

     The preferred stock amounts outstanding as of December 31, 2006 and 2005 are as follows:

		Shares Outstanding		December 31,
Series	Redemption Price	2006	2005	2006	2005
		(Millions of dollars)
Redeemable Serial Preferred
$100 per share par value:      3.70%-5.00%	$103-$105	181,698	181,698	$18.2	$18.2

(1) On January 18, 2007, DPL redeemed all of the outstanding shares of its Redeemable Serial Preferred Stock, at prices ranging from 103% to 105% of par, in an aggregate amount of approximately $18.9 million.

(10)FAIR VALUES OF FINANCIAL INSTRUMENTS

     The estimated fair values of DPL's financial instruments at December 31, 2006 and 2005 are shown below.

	2006		2005
	Carrying Amount	Fair Value	Carrying Amount	Fair Value
	(Millions of dollars)
Assets
Derivative instruments	$  28.7	$  28.7	$  21.6	$  21.6
Liabilities and Capitalization
Long-term debt	$551.8	$549.6	$516.4	$524.1
Redeemable serial preferred stock	$  18.2	$  17.3	$  18.2	$  12.8
Derivative instruments	$  27.6	$  27.6	$  21.6	$  21.6

     The methods and assumptions below were used to estimate, at December 31, 2006 and 2005, the fair value of each class of financial instruments shown above for which it is practicable to estimate a value.

     The fair values of derivative instruments were derived based on quoted market prices.

     The fair values of the Long-term debt, which includes First Mortgage Bonds, Amortizing First Mortgage Bonds, Unsecured Tax-Exempt Bonds, Medium-Term Notes, and Unsecured Notes, 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 value of the Redeemable serial preferred stock, excluding amounts due within one year, were derived based on quoted market prices or discounted cash flows using current rates of preferred stock with similar terms.

     The carrying amounts of all other financial instruments in DPL's accompanying financial statements approximate fair value.

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(11)  COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Rate Proceedings

     DPL currently has two active distribution base rate cases underway: a gas distribution base rate case in Delaware (which is the subject of a settlement agreement as discussed below) and an electric base rate case in Maryland. In each of these cases, DPL has proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers. The BSA will increase rates if revenues from distribution deliveries fall below the level approved by the applicable regulatory commission and will decrease rates if revenues from distribution deliveries are above the commission-approved level. The end result will be that DPL will collect its authorized revenues for distribution deliveries. As a consequence, a BSA "decouples" revenue from unit sales consumption and ties the growth in revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, the refore, provides for more predictable utility distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers' delivery bills, and (iv) removes any disincentives for DPL to promote energy efficiency programs for its customers, because it breaks the link between overall sales volumes and delivery revenues. DPL has proposed a monthly BSA in the gas base rate case and a quarterly BSA in the electric base rate case.

     Delaware

     On August 31, 2006, DPL submitted its 2006 Gas Cost Rate (GCR) filing to the DPSC, which permits DPL to recover gas procurement costs through customer rates. The proposed decrease of approximately 9.6% is in anticipation of decreasing natural gas commodity costs. On October 3, 2006, the DPSC issued its initial order approving the proposed rates, which became effective November 1, 2006, subject to refund pending final DPSC approval after evidentiary hearings. Any amounts subject to refund would be deferred, resulting in no earnings impact.

     On February 23, 2007, DPL submitted an additional filing to the DPSC that proposed a 4.3% decrease in the GCR effective April 1, 2007, in compliance with its gas service tariff and to ensure collections are more aligned with expenses. DPL expects DPSC approval of the rate decrease in late March 2007, subject to refund pending final DPSC approval after evidentiary hearings.

     On August 31, 2006, DPL submitted an application to the DPSC for an increase in gas distribution base rates, including a proposed BSA. The application requested an annual increase of approximately $15 million or an overall increase of 6.6%, including certain miscellaneous tariff fees, reflecting a proposed return on equity (ROE) of 11.00%. If the BSA is not approved, the proposed annual increase would be $15.5 million or an overall increase of 6.8%, reflecting an ROE of 11.25%. On October 17, 2006, the DPSC authorized DPL to place into effect beginning November 1, 2006, subject to refund, gas base rates designed to produce an annual interim increase in revenue of approximately $2.5 million. On February 16, 2007, all of the parties in this proceeding (DPL, DPSC staff and the Delaware Division of Public Advocate) filed a settlement agreement with the DPSC. The settlement provisions include a $9.0 million increase in distribution rates, including certain miscellaneous tarif f fees (of which $2.5 million was put into effect on November 1, 2006, as noted above), an ROE of 10.25%, and a change in

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depreciation rates that result in a $2.1 million reduction in pre-tax annual depreciation expense. Although the settlement agreement does not include a BSA, it provides for all of the parties to the case to participate in any generic statewide proceeding for the purpose of investigating BSA mechanisms for electric and gas distribution utilities. In a separate proceeding, DPL has requested that a docket be opened for this purpose. Under the settlement agreement, rates will become effective on April 1, 2007. A DPSC decision is expected by the end of March 2007.

     Maryland

     On November 17, 2006, DPL submitted an application to the MPSC to increase electric distribution base rates, including a proposed BSA. The application requested an annual increase of approximately $18.4 million or an overall increase of 3.2%, including certain miscellaneous tariff fees, reflecting a proposed ROE of 11.00%. If the BSA is not approved, the proposed annual increase would be $20.3 million or an overall increase of 3.6%, reflecting a proposed ROE of 11.25%. The application also proposed a Pension/OPEB Expense Surcharge that would allow DPL to reflect in its distribution rates the increases and decreases that occur in the level of its pension and other post-employment benefits expense. The application requested that rates go into effect on December 17, 2006. In an order dated December 11, 2006, the MPSC suspended the proposed rates pending MPSC approval. An MPSC decision is expected in June 2007.

     Federal Energy Regulatory Commission

     On May 15, 2006, DPL updated its FERC-approved formula transmission rates based on its FERC Form 1 data for 2005. This new rate of $10,034 per megawatt per year became effective on June 1, 2006. By operation of the formula rate process, the new rate incorporates true-ups from the 2005 formula rate that was effective June 1, 2005 and the new 2005 customer demand or peak load. Also, beginning in January 2007, the new rate will be applied to 2006 customer demand data, replacing the 2005 demand data that is currently used. This demand component is driven by DPL's prior year peak load. Further, the rate changes will be positively impacted by changes to distribution rates based on the merger settlements in Maryland. The net earnings impact expected from the network transmission rate changes is estimated to be a reduction of approximately $3 million year over year (2005 to 2006).

Default Electricity Supply Proceedings

     Delaware

     Effective May 1, 2006, SOS replaced fixed-rate POLR service for customers who do not choose an alternative electricity supplier. In October 2005, the DPSC approved DPL as the SOS provider to its Delaware delivery customers. DPL obtains the electricity to fulfill its SOS supply obligation under contracts entered pursuant to a competitive bid procedure approved by the DPSC. The bids received for the May 1, 2006, through May 31, 2007, period have had the effect of increasing rates significantly for all customer classes, including an average residential customer increase of 59%, as compared to the fixed rates previously in effect.

     To address this increase in rates, Delaware in April 2006 enacted legislation that provides for a deferral of the financial impact on customers of the increases through a three-step phase-in of the rate increases, with 15% of the increase taking effect on May 1, 2006, 25% of the increase taking effect on January 1, 2007, and any remaining balance taking effect on June 1, 2007, subject to the right of customers to elect not to participate in the deferral program. Customers who do not "opt-out" of the rate deferral program are required to pay the amounts deferred,

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without any interest charge, over a 17-month period beginning January 1, 2008. As of December 31, 2006, approximately 53% of the eligible Delaware customers have opted not to participate in the deferral of the SOS rates offered by DPL. With approximately 47% of the eligible customers participating in the phase-in program, DPL anticipates a maximum deferral balance of $51.4 million.

     Maryland

     Pursuant to an order issued by the MPSC in November 2006, DPL is the SOS provider to its delivery customers who do not choose an alternative electricity supplier. DPL purchases the power supply required to satisfy its SOS obligations from wholesale suppliers under contracts entered into pursuant to a competitive bid procedure approved and supervised by the MPSC. In March 2006, DPL announced the results of competitive bids to supply electricity to its Maryland SOS customers for one year beginning June 1, 2006. Due to significant increases in the cost of fuels used to generate electricity, the auction results had the effect of increasing the average monthly electric bill by about 35% for DPL's Maryland residential customers.

     On April 21, 2006, the MPSC approved a settlement agreement among DPL, its affiliate Pepco, the staff of the MPSC and the Office of Peoples Counsel of Maryland, which provides for a rate mitigation plan for the residential customers of DPL. Under the plan, the full increase for DPL's residential customers who affirmatively elect to participate are being phased-in in increments of 15% on June 1, 2006, 15.7% on March 1, 2007 and the remainder on June 1, 2007. Customers electing to participate in the rate deferral plan will be required to pay the deferred amounts over an 18-month period beginning June 1, 2007. DPL will accrue the interest cost to fund the deferral program. The interest cost will be absorbed by DPL during the period that the deferred balance is accumulated and collected from customers, to the extent of and offset against the margins that the companies otherwise would earn for providing SOS to residential customers. As of December 31, 2006, approximately 1% o f DPL's residential customers had elected to participate in the phase-in program.

     On June 23, 2006, Maryland enacted legislation that extended the period for customers to elect to participate in the phase-in of higher rates and revised the obligation to provide SOS to residential and small commercial customers until further action of the General Assembly. The legislation also provides for a customer refund reflecting the difference between the interest expense on an initially projected deferred balance at a 25% customer participation level and the interest expense on a deferred balance based on actual participation levels referred to above. The total amount of the refund is approximately $.3 million for DPL customers. At DPL's 1% level of participation, DPL estimates that the deferral balance, net of taxes, will be approximately $.2 million. In July 2006, the MPSC approved a revised tariff rider filed in June 2006 by DPL to implement the legislation.

     Virginia

     On March 10, 2006, DPL filed for a rate increase with the VSCC for its Virginia Default Service customers to take effect on June 1, 2006, which was intended to allow DPL to recover its higher cost for energy established by the competitive bid procedure. On June 19, 2006, the VSCC issued an order that granted a rate increase for DPL of $11.5 million ($8.5 million less than requested by DPL in its March 2006 filing), to go into effect July 1, 2006. In determining the amount of the approved increase, the VSCC applied the proxy rate calculation to DPL's fuel factor, rather than allowing full recovery of the costs DPL incurred in procuring the supply

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necessary for its Default Service obligation. The estimated after-tax earnings and cash flow impacts of the decision are reductions of approximately $3.6 million in 2006 (including the loss of revenue in June 2006 associated with the Default Service rate increase being deferred from June 1 until July 1) and $2.0 million in 2007. The order also mandated that DPL file an application by March 1, 2007 (which has been delayed until April 2, 2007 by subsequent VSCC order) for Default Service rates to become effective June 1, 2007, which should include a calculation of the fuel factor that is consistent with the procedures set forth in the order.

     In February 2007, the Virginia General Assembly passed amendments to the Virginia Electric Utility Restructuring Act (the Virginia Restructuring Act) that modified the method by which investor-owned electric utilities in Virginia will be regulated by the VSCC. These amendments to the Virginia Restructuring Act, subject to further amendment or veto by the Virginia governor and subsequent action by the General Assembly, will be effective on July 1, 2007. The amendments provide that, as of December 31, 2008, the following will come to an end: (i) capped rates (the previous expiration date was December 31, 2010); (ii) DPL's Default Service obligation (previously, DPL was obligated to continue to offer Default Service until relieved of that obligation by the VSCC); and (iii) customer choice, except that customers with loads of 5 megawatts or greater will continue to be able to buy from competitive suppliers, as will smaller non-residential customers tha t aggregate their loads to reach the 5 megawatt threshold and obtain VSCC approval. Additionally, if an ex-customer of Default Service wants to return to DPL as its energy supplier, it must give 5 years notice or obtain approval of the VSCC that the return is in the public interest. In this event, the ex-customer must take DPL's service at market based rates. DPL also believes that the amendments to the Virginia Restructuring Act will terminate, as of December 31, 2008, the ratemaking provisions within the memorandum of agreement entered into by DPL, the staff of the VSCC and the Virginia Attorney General's office in the docket approving DPL's generating asset divestiture in 2000 (the MOA), including the application of the proxy rate calculation to DPL's fuel factor as discussed above; however, the VSCC's interpretation of these provisions is not known. It should be noted that in DPL's view, in the absence these amendments, the MOA and all of its provisions (including the proxy rate calculation) expire o n July 1, 2007; the VSCC staff and the Virginia Attorney General disagree with DPL's position. Assuming the ratemaking provisions of the MOA end on December 31, 2008 pursuant to the amended Virginia Restructuring Act, the amendments provide that DPL shall file a rate case in 2009 and every 2 years thereafter. The ROE to be allowed by the VSCC will be set within a range, the lower of which is essentially the average of vertically integrated investor-owned electric utilities in the southeast with an upper point that is 300 basis points above that average. The VSCC has authority to set rates higher or lower to allow DPL to maintain the opportunity to earn the determined ROE and to credit back to customers, in whole or in part, earnings that were 50 basis points or more in excess of the determined ROE. The amended Virginia Restructuring Act includes various incentive ROEs for the construction of new generation and would allow the VSCC to penalize or reward DPL for efficient operations or, if DPL were to add new generation, for generating unit performance. There are also enhanced ratemaking features if DPL pursues conservation, demand management and energy efficiency programs or pursues renewable energy portfolios.

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

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abandoned or unremediated hazardous waste sites. DPL may incur costs to clean up currently or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. Although penalties assessed for violations of environmental laws and regulations are not recoverable from DPL's customers, environmental clean-up costs incurred by DPL would be included in its cost of service for ratemaking purposes.

     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 a Cambridge, Maryland site on DPL-owned property and to investigate the extent of MGP contamination on adjacent property. The MDE has approved the RI and DPL submitted a final FS to MDE on February 15, 2007. The costs of cleanup (as determined by the RI/FS and subsequent negotiations with MDE) are anticipated to be approximately $2.7 million. The remedial action will include dredging activities within Cambridge Creek, which are expected to take place as early as October 2007, and soil excavation on DPL's and adjacent property as early as January 2008.

     In the early 1970s, DPL sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a nonaffiliated company. In December 1987, DPL was notified by the U.S. Environmental Protection Agency (EPA) that it, along with a number of other utilities and non-utilities, was a potentially responsible party 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 Metal Bank/Cottman Avenue site. The de minimis settlement did not resolve DPL's responsibility for natural resource damages, if any, at the site. DPL believes that any liability for natural resource damages at this site will not have a material adverse effect on its financial position, results of operations or cash flows.

IRS Mixed Service Cost Issue

     During 2001, DPL changed its method of accounting with respect to capitalizable construction costs for income tax purposes. The change allowed DPL to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through December 31, 2005, these accelerated deductions generated incremental tax cash flow benefits of approximately $62 million, primarily attributable to its 2001 tax returns.

     On August 2, 2005, the Treasury Department released regulations that, if adopted in their current form, would require DPL to change its method of accounting with respect to capitalizable construction costs for income tax purposes for future tax periods beginning in 2005. Based on those regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believes will be acceptable to the Internal Revenue Service (IRS).

     On the same day that the new regulations were released, the IRS issued Revenue Ruling 2005-53, which is intended to limit the ability of certain taxpayers to utilize the method of accounting for income tax purposes they utilized on their tax returns for 2004 and prior years with respect to capitalizable construction costs. In line with this Revenue Ruling, the IRS revenue agent's report for the 2001 and 2002 tax returns disallowed substantially all of the

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incremental tax benefits that DPL had claimed on those returns by requiring it to capitalize and depreciate certain expenses rather than treat such expenses as current deductions. PHI's protest of the IRS adjustments is among the unresolved audit matters relating to the 2001 and 2002 audits pending before the Appeals Office.

     In February 2006, PHI paid approximately $121 million of taxes to cover the amount of taxes that management estimated to be payable based on the method of tax accounting that PHI, pursuant to the proposed regulations, has adopted on its 2005 tax return. However, if the IRS is successful in requiring DPL to capitalize and depreciate construction costs that result in a tax and interest assessment greater than management's estimate of $121 million, PHI will be required to pay additional taxes and interest only to the extent these adjustments exceed the $121 million payment made in February 2006.

Contractual Obligations

     As of December 31, 2006, DPL's contractual obligations under non-derivative fuel and power purchase contracts were $602.2 million in 2007, $387.7 million in 2008 to 2009, $35.6 million in 2010 to 2011, and $37.0 million in 2012 and thereafter.

(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 by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to DPL for the years ended December 31, 2006, 2005 and 2004 were $100.5 million, $98.4 million and $99.5 million, respectively.

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

	For the Year Ended December 31,
	2006	2005	2004
(Expense) Income	(Millions of dollars)
Full Requirements Contract with Conectiv   Energy Supply for power, capacity and   ancillary services to service Provider   of Last Resort Load (a)	$(122.2)	$(426.1)	$(510.5)
SOS with Conectiv Energy Supply (a)	(213.7)	(53.4)	(11.3)
Intercompany lease transactions (b)	8.9	8.3	8.6
Transcompany pipeline gas sales with Conectiv Energy Supply (c)	2.8	7.5	-
Transcompany pipeline gas purchase with Conectiv Energy Supply (d)	$   (2.9)	$  (5.4)	$  (1.2)

(a)	Included in fuel and purchased energy.
(b)	Included in electric revenue.
(c)	Included in gas revenue.
(d)	Included in gas purchased.

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     As of December 31, 2006 and 2005, DPL had the following balances on its balance sheets due (to)/from related parties:

	2006	2005
Asset (Liability)	(Millions of dollars)
Receivable from Related Party (current)PHI Service Company	$  46.4	$        -
Payable to Related Party (current)
PHI Parent	$(24.7)	$     (.1)
PHI Service Company	-	(12.2)
Conectiv Energy Supply	(24.6)	(45.3)
Pepco Energy Services	(7.7)	-
The items listed above are included in the "Accounts payable to   associated companies" balance on the Balance Sheet of $9.6   million and $57.3 million at December 31, 2006 and 2005,   respectively.
Money Pool Balance with Pepco Holdings     (included in short-term debt)	$     -	$(60.7)
Money Pool Interest Accrued (included in interest accrued)	$     -	$    (.2)

(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 and differences between summer and winter rates.

	2006
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Total
	(Millions of dollars)
Total Operating Revenue	$368.5	$339.3	$394.9	$320.7	$1,423.4
Total Operating Expenses	324.0	317.4	374.8	295.7	1,311.9
Operating Income	44.5	21.9	20.1	25.0	111.5
Other Expenses	(8.5)	(8.8)	(9.7)	(9.9)	(36.9)
Income Before Income Tax Expense	36.0	13.1	10.4	15.1	74.6
Income Tax Expense	15.2	6.2	5.1	5.6	32.1
Net Income	20.8	6.9	5.3	9.5	42.5
Dividends on Preferred Stock	.2	.2	.2	.2	.8
Earnings Available for Common Stock	$  20.6	$   6.7	$   5.1	$   9.3	$    41.7

	2005
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Total
	(Millions of dollars)
Total Operating Revenue	$370.7	$288.9	$373.7	$310.5	$1,343.8
Total Operating Expenses	318.4	259.7	323.0	280.3	1,181.4
Operating Income	52.3	29.2	50.7	30.2	162.4
Other Expenses	(7.9)	(7.8)	(7.3)	(7.1)	(30.1)
Income Before Income Taxes	44.4	21.4	43.4	23.1	132.3
Income Tax Expense	18.3	8.9	19.6 (a)	10.8 (b)	57.6
Net Income	26.1	12.5	23.8	12.3	74.7
Dividends on Preferred Stock	.3	.2	.3	.2	1.0
Earnings Available for   Common Stock	$  25.8	$  12.3	$ 23.5	$ 12.1	$   73.7

Note:	Sales of electric energy are seasonal and, accordingly, comparisons by quarter within a year are not meaningful.
(a)	Includes $2.0 million in income tax expense related to the mixed service cost issue under IRS Ruling 2005-53.
(b)	Includes $1.0 million in income tax expense related to the mixed service cost issue under IRS Ruling 2005-53.

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(14)  SUBSEQUENT EVENT

     On January 18, 2007, DPL redeemed all outstanding shares of its Redeemable Serial Preferred Stock of each series at redemption prices ranging from 103% to 105% of par, for an aggregate redemption amount of approximately $18.9 million.

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Report of Independent Registered Public Accounting Firm

To the Shareholder and 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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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 statement schedule based on our audits. We c onducted 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.

PricewaterhouseCoopers LLP
Washington, DC
March 1, 2007

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF EARNINGS
For the Year Ended December 31,	2006	2005	2004
(Millions of dollars)
Operating Revenue	$1,373.3	$1,350.1	$1,213.3
Operating Expenses
Fuel and purchased energy	924.2	850.9	745.8
Other operation and maintenance	147.7	154.5	156.6
Depreciation and amortization	111.3	122.2	131.2
Other taxes	22.9	22.6	20.4
Deferred electric service costs	15.0	56.6	20.3
Gain on sales of assets	-	-	(14.7)
Total Operating Expenses	1,221.1	1,206.8	1,059.6
Operating Income	152.2	143.3	153.7
Other Income (Expenses)
Interest and dividend income	2.3	1.9	.7
Interest expense	(63.7)	(58.9)	(60.7)
Other income	5.4	6.0	5.8
Other expense	(3.1)	-	-
Total Other Expenses	(59.1)	(51.0)	(54.2)
Income Before Income Tax Expense and   Extraordinary Item	93.1	92.3	99.5
Income Tax Expense	33.0	41.2	40.7
Income from Continuing Operations	60.1	51.1	58.8
Discontinued Operations (Note 13)
Income from operations (net of tax of        $1.8 million, $2.1 million,       and $1.9 million, respectively)	2.6	3.1	2.9
Income Before Extraordinary Item	62.7	54.2	61.7
Extraordinary Item (net of tax of $6.2 million)	-	9.0	-
Net Income	62.7	63.2	61.7
Dividends on Redeemable Serial Preferred Stock	.3	.3	.3
Earnings Available for Common Stock	$   62.4	$   62.9	$   61.4
The accompanying Notes are an integral part of these Consolidated Financial Statements.

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS
ASSETS	December 31, 2006	December 31, 2005
(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents	$    5.5	$    8.2
Restricted cash	9.0	11.5
Accounts receivable, less allowance for uncollectible      accounts of $5.5 million and $5.2 million, respectively	163.0	206.0
Fuel, materials and supplies - at average cost	12.6	39.6
Prepayments of income taxes	54.5	-
Prepaid expenses and other	16.9	12.3
B.L. England assets held for sale	14.4	-
Total Current Assets	275.9	277.6
INVESTMENTS AND OTHER ASSETS
Regulatory assets	857.5	910.4
Restricted funds held by trustee	17.5	11.1
Prepaid pension expense	11.7	8.0
Other	19.5	22.6
B.L. England assets held for sale	79.2	-
Total Investments and Other Assets	985.4	952.1
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	1,942.9	1,915.6
Accumulated depreciation	(599.1)	(585.3)
Net Property, Plant and Equipment	1,343.8	1,330.3
TOTAL ASSETS	$2,605.1	$2,560.0
The accompanying Notes are an integral part of these Consolidated Financial Statements.

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER'S EQUITY	December 31, 2006	December 31, 2005
(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$    23.8	$    22.6
Current maturities of long-term debt	45.9	94.0
Accounts payable and accrued liabilities	110.3	182.2
Accounts payable to associated companies	27.3	38.3
Taxes accrued	8.5	75.8
Interest accrued	13.7	12.9
Other	38.1	37.3
Liabilities associated with B.L. England assets held for sale	.9	-
Total Current Liabilities	268.5	463.1
DEFERRED CREDITS
Regulatory liabilities	360.2	206.3
Income taxes	441.0	432.5
Investment tax credits	14.9	16.5
Other postretirement benefit obligation	27.1	46.4
Other	14.0	20.2
Liabilities associated with B.L. England assets held for sale	78.6	-
Total Deferred Credits	935.8	721.9
LONG-TERM LIABILITIES
Long-term debt	465.7	376.7
Transition Bonds issued by ACE Funding	464.4	494.3
Capital lease obligations	-	.2
Total Long-Term Liabilities	930.1	871.2
COMMITMENTS AND CONTINGENCIES (NOTE 11)
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 shares outstanding	25.6	25.6
Premium on stock and other capital contributions	306.9	293.4
Retained earnings	132.0	178.6
Total Shareholder's Equity	464.5	497.6
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$2,605.1	$2,560.0
The accompanying Notes are an integral part of these Consolidated Financial Statements.

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Year Ended December 31,	2006	2005	2004
(Millions of dollars)
OPERATING ACTIVITIES
Net income	$    62.7	$    63.2	$   61.7
Adjustments to reconcile net income to net cash from operating activities:
Extraordinary item	-	(15.2)	-
Gain on sale of assets	-	-	(14.7)
Depreciation and amortization	111.3	122.2	131.2
Investment tax credit adjustments	(1.4)	(3.2)	(4.7)
Deferred income taxes	3.6	(77.4)	(18.4)
Other deferred charges	(9.0)	1.7	(6.5)
Other deferred credits	(.3)	.7	(5.0)
Other postretirement benefit obligations	2.7	1.7	1.1
Prepaid pension expense	4.8	(52.0)	6.9
Changes in:
Accounts receivable	41.6	(29.6)	(.5)
Regulatory assets and liabilities	17.9	122.5	33.6
Material and supplies	9.8	(1.5)	(3.8)
Prepaid expenses	1.7	1.6	(.2)
Accounts payable and accrued liabilities	(105.5)	129.4	(12.2)
Interest and taxes accrued	(119.2)	55.0	1.4
Net Cash From Operating Activities	20.7	319.1	169.9
INVESTING ACTIVITIES
Investment in property, plant and equipment	(108.3)	(117.2)	(160.2)
Proceeds from/changes in:
Proceeds from sale of other assets	177.0	-	11.0
Change in restricted cash	2.4	2.2	1.5
Net other investing activities	-	(.5)	-
Net Cash From (Used By) Investing Activities	71.1	(115.5)	(147.7)
FINANCING ACTIVITIES
Common stock repurchased	-	-	(67.6)
Dividends paid to Pepco Holdings	(109.0)	(95.9)	(10.6)
Dividends paid on preferred stock	(.3)	(.3)	(.3)
Redemption of debentures issued to financing trust	-	-	(25.0)
Issuances of long-term debt	105.0	-	174.7
Redemptions of long-term debt	(94.0)	(68.1)	(229.1)
Principal portion of capital lease payments	-	-	.2
Issuances (repayments) of short-term debt, net	1.2	(32.7)	32.7
Net other financing activities	2.6	(2.7)	.2
Net Cash Used By Financing Activities	(94.5)	(199.7)	(124.8)
Net (Decrease) Increase In Cash and Cash Equivalents	(2.7)	3.9	(102.6)
Cash and Cash Equivalents at Beginning of Year	8.2	4.3	106.9
CASH AND CASH EQUIVALENTS AT END OF YEAR	$    5.5	$    8.2	$    4.3
NON-CASH ACTIVITIES
Excess accumulated depreciation transferred to regulatory liabilities	$        -	$ 131.0	$        -
Capital contribution in respect of certain intercompany transactions	$  13.5	$        -	$    5.7
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest (net of capitalized interest of $.8 million, $.8 million,     and $1.2 million, respectively) and paid for income taxes:
Interest	$  60.2	$  57.5	$  60.7
Income taxes	$129.2	$  73.6	$  56.8
The accompanying Notes are an integral part of these Consolidated Financial Statements.

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
			Premium on Stock	Capital Stock Expense	Retained Earnings
	Common Stock       Shares        Par Value
(Millions of dollars, except shares)
BALANCE, DECEMBER 31, 2003	12,886,853	$38.7	$343.0	$  (.8)	$160.8
Net Income	-	-	-	-	61.7
Dividends:
Preferred stock	-	-	-	-	(.3)
Common stock	-	-	-	-	(10.6)
Common stock repurchased	(4,340,836)	(13.1)	(54.7)	.2	-
Capital contribution	-	-	5.7	-	-
BALANCE, DECEMBER 31, 2004	8,546,017	$25.6	$294.0	$  (.6)	$211.6
Net Income	-	-	-	-	63.2
Dividends:
Preferred stock	-	-	-	-	(.3)
Common stock	-	-	-	-	(95.9)
BALANCE, DECEMBER 31, 2005	8,546,017	$25.6	$294.0	$  (.6)	$178.6
Net Income	-	-	-	-	62.7
Dividends:
Preferred stock	-	-	-	-	(.3)
Common stock	-	-	-	-	(109.0)
Capital contribution	-	-	13.5	-	-
BALANCE, DECEMBER 31, 2006	8,546,017	$25.6	$307.5	$  (.6)	$132.0
The accompanying Notes are an integral part of these Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ATLANTIC CITY ELECTRIC COMPANY

(1)ORGANIZATION

     Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey. ACE's service territory covers 2,700 square miles and has a population of approximately 1.0 million. ACE provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is also known as Basic Generation Service (BGS). ACE is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI). Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between PHI and ACE and certain activities of ACE are subject to the regulatory oversight of the Federal Energy Regulatory Commission (FERC) under PUHCA 2005.

     As discussed in Note (11) Commitments and Contingencies, herein, in addition to its electricity transmission and distribution operations, during 2006 ACE owned a 2.47% undivided interest in the Keystone electric generating facility, a 3.83% undivided interest in the Conemaugh electric generating facility (with a combined generating capacity of 108 megawatts), and also owned the B.L. England electric generating facility (with a generating capacity of 447 megawatts). On September 1, 2006, ACE sold its interests in the Keystone and Conemaugh generating facilities and on February 8, 2007, ACE completed the sale of the B.L. England generating facility.

(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 investee. 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 Earnings. Additionally, individual interests in several jointly owned electric plants previously held by ACE, and certain transmission and other facilities currently held are consolidated in proportion to ACE's percentage interest in the facility.

     In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R (Revised December 2003), entitled "Consolidation of Variable Interest Entities" (FIN 46R), ACE deconsolidated its trust preferred securities that had previously been consolidated. FIN 46R addresses conditions when an entity should be consolidated based upon variable interests rather than voting interests. For additional information regarding the impact of implementing FIN 46R, see the FIN 46R discussion later in this Note.

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Use of Estimates

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP), such as compliance with 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 assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, and income tax-provisions and reserves. Additionally, ACE is subject to legal, regulatory, and other proceedings and claims t hat arise in the ordinary course of its business. ACE records an estimated liability for these proceedings and claims based upon the probable and reasonably estimable criteria contained in Statement of Financial Accounting Standards (SFAS) No. 5, "Accounting for Contingencies." Although ACE believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Change in Accounting Estimates

     During 2005, ACE recorded the impact of a reduction in estimated unbilled revenue, primarily reflecting an increase in the estimated amount of power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). This change in accounting estimate reduced net earnings for the year ended December 31, 2005 by approximately $6.4 million.

Revenue Recognition

     ACE recognizes revenue for the supply and delivery of electricity upon delivery to its customers, including amounts for services rendered, but not yet billed (unbilled revenue). ACE recorded amounts for unbilled revenue of $31.8 million and $42.0 million as of December 31, 2006 and December 31, 2005, respectively. These amounts are included in the "accounts receivable" line item in the accompanying Consolidated Balance Sheets. ACE calculates unbilled revenue using an output based methodology. This methodology is based on the supply of electricity or gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix and estimated power line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers), which are inherently uncertain and susceptible to change from period to period, the impact of which could be material.

     The taxes related to the delivery of electricity to its customers are a component of ACE's tariffs and, as such, are billed to customers and recorded in Operating Revenues. Accruals for these taxes by ACE are recorded in Other Taxes. Excise tax related generally to the consumption of gasoline by ACE in the normal course of business is charged to operations, maintenance or construction, and is de minimis.

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Regulation of Power Delivery Operations

     Certain aspects of ACE's utility businesses are subject to regulation by the New Jersey Board of Public Utilities (NJBPU) and its wholesale operations are subject to regulation by 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 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 must be charged to earnings.

     The components of ACE's regulatory asset balances at December 31, 2006 and 2005 are as follows:

	2006	2005
	(Millions of dollars)
Securitized stranded costs	$773.0	$  823.5
Deferred recoverable income taxes	18.1	16.1
Deferred debt extinguishment costs	15.3	16.6
Deferred other postretirement benefit costs	15.0	17.5
Unrecovered purchased power contract costs	11.1	12.2
Asset retirement cost	33.0	-
Other	25.0	24.5
Total regulatory assets	$890.5	$  910.4
Less: B.L. England regulatory assets held for sale	33.0	-
Total regulatory assets per balance sheet	$857.5	$910.4

     The components of ACE's regulatory liability balances at December 31, 2006 and 2005 are as follows:

	2006	2005
	(Millions of dollars)
Excess depreciation reserve	$105.8	$121.7
Deferred energy supply costs	164.9	40.9
Asset retirement obligation	63.2	-
Regulatory liability for Federal and New Jersey   tax benefit and other	41.1	43.7
Gain from sale of Keystone and Conemaugh	48.4	-
Total regulatory liabilities	$423.4	$206.3
Less: B.L. England regulatory liabilities associated with           B.L. England regulatory assets held for sale	63.2	-
Total regulatory liabilities per balance sheet	$360.2	$206.3

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     A description for each category of regulatory assets and regulatory liabilities follows:

     Securitized Stranded Costs: Represents stranded costs associated with a non-utility generator 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) (Transition Bonds). A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. The stranded costs are amortized over the life of the Transition Bonds, which mature between 2010 and 2023.

     Deferred Energy Supply Costs: The regulatory liability balances of $164.9 and $40.9 for the years ended December 31, 2006 and 2005, respectively, primarily represent deferred costs relating to a net over-recovery by ACE connected with the provision of BGS and other restructuring related costs incurred by ACE. This deferral received a return and is being recovered over 8 years, beginning in 2007.

     Deferred Recoverable Income Taxes:  Represents a receivable from our customers for tax benefits ACE has previously flowed through before the company was ordered to provide deferred income taxes. As the temporary differences between the financial statement and tax basis of assets reverse, the deferred recoverable balances are reversed. 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.

     Deferred Other Postretirement Benefit Costs: Represents the non-cash portion of other postretirement 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 Contract Costs:  Represents deferred costs related to purchase power contracts at ACE, which are being recovered from July 1994 through May 2014 and which earn a return.

     Asset Retirement Obligation: During the first quarter of 2006, ACE recorded an asset retirement obligation of $60 million for B.L. England plant demolition and environmental remediation costs. Amortization of the liability is over a two-year period amortized quarterly. The cumulative amortization of $33.0 million at December 31, 2006, is recorded as a regulatory asset -- "Asset Retirement Cost." As discussed in Note (11) Commitments and Contingencies, on February 8, 2007, ACE completed the sale of the B.L. England generating facility.

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

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     Excess Depreciation Reserve: The excess depreciation reserve was recorded as part of a New Jersey rate case settlement. This excess reserve is the result of a change in estimated depreciable lives and a change in depreciation technique from remaining life to whole life. The excess is being amortized over an 8.25 year period, which began in June 2005.

     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 on ACE's Consolidated Balance Sheets until such time as the Internal Revenue Service issues its final regulations with respect to normalization of these federal excess deferred taxes.

     Gain from Sale of Keystone and Conemaugh: On September 1, 2006, ACE completed the sale of its interests in the Keystone and Conemaugh generating facilities to Duquesne Light Holdings Inc. for approximately $177.0 million, which was subsequently decreased by $1.6 million based on a post-closing 60-day true-up for applicable items not known at the time of the closing. The total gain recognized on this sale, net of adjustments, came to $131.4 million. Approximately $81.3 million of the net gain from the sale has been used to offset the remaining regulatory asset balance, which ACE has been recovering in rates, and approximately $49.8 million of the net gain is being returned to ratepayers over a 33-month period as a credit on their bills, which began during the October 2006 billing period. The balance to be repaid to customers is $48.4 million as of December 31, 2006.

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 ACE and certain other PHI 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 zero and $4.0 million at December 31, 2006, and 2005, 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. 71, utilities can capitalize as Allowance for Funds Used During Construction (AFUDC) the capital costs of financing the construction of plant and equipment. The debt portion of AFUDC is recorded as a reduction of "interest expense" and the equity portion of AFUDC is credited to "other income" in the accompanying Consolidated Statements of Earnings.

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     ACE recorded AFUDC for borrowed funds of $.8 million, $.8 million and $1.2 million for the years ended December 31, 2006, 2005 and 2004, respectively.

     ACE recorded amounts for the equity component of AFUDC of $.7 million, $1.6 million and $1.7 million for the years ended December 31, 2006, 2005 and 2004, respectively.

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 businesses, is included in interest expense.

Emission Allowances

     Emission allowances for sulfur dioxide (SO₂) and nitrous oxide (NO_x) are allocated to generation owners by the U.S. Environmental Protection Agency (EPA) based on Federal programs designed to regulate the emissions from power plants. The EPA allotments have no cost basis to the generation owners. Depending on the run-time of a generator in a given year, and other pollution controls it may have, the unit may need additional allowances above its allocation, or it may have excess allowances that it does not need. Allowances are traded among companies in an over-the-counter market, which allows companies to purchase additional allowances to avoid incurring penalties for noncompliance with applicable emissions standards or to sell excess allowances.

     ACE accounts for emission allowances as inventory in the balance sheet line item "Fuel, materials and supplies - at average cost." Allowances from EPA allocation are added to current inventory each year at a zero basis. Additional purchased allowances are recorded at cost. Allowances sold or consumed at the power plants are expensed at a weighted-average cost. This cost tends to be relatively low due to the zero-basis allowances. At December 31, 2006 and 2005, the book value of emission allowances was $.4 million and $1.8 million, respectively. ACE has established a committee to ensure its plants are in compliance with emissions regulations and that its power plants have the required number of allowances on hand.

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 amounts, 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 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

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Sheets. For additional information, see the discussion under "Regulation of Power Delivery Operations" 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 Postretirement Benefit Plans

     Pepco Holdings sponsors a retirement plan that covers substantially all employees of ACE (the PHI Retirement Plan) and certain employees of other Pepco Holdings subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.

     The PHI Retirement Plan is accounted for in accordance with SFAS No. 87, "Employers' Accounting for Pensions," and its other postretirement benefits in accordance with SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." Pepco Holdings' financial statement disclosures were prepared in accordance with SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits."

     SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R)"

     In September 2006, the FASB issued SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R)" (SFAS No. 158). SFAS No. 158 requires that companies recognize a net liability or asset to report the funded status of their defined benefit pension and other postretirement benefit plans on the balance sheet. Recognizing the funded status of the company's benefit plans as a net liability or asset will require an offsetting adjustment to accumulated other comprehensive income in shareholders' equity or will be deferred as a regulatory asset or liability if probable of recovery in rates under SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS No. 158 does not change how pension and other postretirement benefits are accounted for and reported in the income statement.

     ACE participates in benefit plans sponsored by Pepco Holdings and as such, the provisions of SFAS No. 158 do not have an impact on its financial condition and cash flows.

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 a significant adverse change in the manner an asset is being used or its physical condition. For long-lived assets that are

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expected to be held and used, SFAS No. 144 requires that an impairment loss be recognized only 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. Property, plant and equipment other than electric facilities is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite depreciation rates for 2006, 2005 and 2004 for ACE's transmission and distribution system property were 2.9%, 3.1% and 3.5%, respectively, and for its generation system property were .3%, 2.4%, and 2.3%, respectively.

Accounts Receivable and Allowance for Uncollectible Accounts

     ACE'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 after the receivable is recorded). ACE uses the allowance method to account for uncollectible accounts receivable.

FIN 46R, "Consolidation of Variable Interest Entities"

     ACE has power purchase agreements (PPAs) with a number of entities, including three contracts between unaffiliated non-utility generators (NUGs) and ACE. Due to a variable element in the pricing structure of the NUGs, ACE potentially assumes the variability in the operations of the plants related to these PPAs and, therefore, has a variable interest in the entities. In accordance with the provisions of FIN 46R, ACE continued, during 2006, to conduct exhaustive efforts to obtain information from these entities, but 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, but have not been able to obtain such information.

     Net power purchase activities with the counterparties to the NUGs for the years ended December 31, 2006, 2005 and 2004, were approximately $324 million, $327 million and $265 million, respectively, of which $288 million, $289 million and $236 million, respectively, related to power purchases under the NUGs. ACE does not have exposure to loss under the PPA agreements since cost recovery will be achieved from its customers through regulated rates.

Prepaid Expenses and Other

     The prepaid expenses and other balance primarily consists of prepayments and the current portion of deferred income tax assets.

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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 other miscellaneous liabilities.

Other Deferred Credits

     The other deferred credits balance principally consists of miscellaneous deferred liabilities.

Dividend Restrictions

     In addition to its future financial performance, the ability of ACE 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, may require the prior approval of ACE's utility regulatory commission before dividends can be paid; (ii) the prior rights of holders of existing and future preferred stock, mortgage bonds and other long-term debt issued by ACE and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of the charter of ACE, which impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. ACE had approximately $97.9 million and $106.0 million of restricted retained earnings at December 31, 2006 and 2005, respectively.

Accounting for Planned Major Maintenance Activities

     In accordance with FASB Staff Position (FSP), American Institute of Certified Public Accountants Industry Audit Guide, Audits of Airlines--"Accounting for Planned Major Maintenance Activities" (FSP AUG AIR-1), the costs associated with planned major maintenance activities related to generation facilities are accounted for on an as incurred basis.

Discontinued Operations

     Discontinued operations are identified and accounted for in accordance with the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." For information regarding ACE's discontinued operations refer to Note (13), "Discontinued Operations," herein.

Reclassifications

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

New Accounting Standards

     EITF 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

     In September 2005, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty" (EITF 04-13),

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which addresses circumstances under which two or more exchange transactions involving inventory with the same counterparty should be viewed as a single exchange transaction for the purposes of evaluating the effect of Accounting Principles Board Opinion 29, "Accounting for Nonmonetary Transactions." EITF 04-13 is effective for new arrangements entered into, or modifications or renewals of existing arrangements, beginning in the first interim or annual reporting period beginning after March 15, 2006.

     ACE implemented EITF 04-13 on April 1, 2006. The implementation did not have a material impact on ACE's overall financial condition, results of operations, or cash flows for the second quarter of 2006.

     FSP FIN 46(R)-6, "Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)"

     In April 2006, the FASB issued FSP FIN 46(R)-6, "Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R), (FSP FIN 46(R)-6)" which provides guidance on how to determine the variability to be considered in applying FIN 46(R), "Consolidation of Variable Interest Entities."

     The guidance in FSP FIN 46(R)-6 is applicable prospectively beginning the first day of the first reporting period beginning after June 15, 2006.

     ACE started applying the guidance in FSP FIN 46(R)-6 to new and modified arrangements effective July 1, 2006.

     EITF Issue No. 06-3, "Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions"

     On June 28, 2006, the FASB ratified EITF Issue No. 06-3, "Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions" (EITF 06-3). EITF 06-3 provides guidance on an entity's disclosure of its accounting policy regarding the gross or net presentation of certain taxes and provides that if taxes included in gross revenues are significant, a company should disclose the amount of such taxes for each period for which an income statement is presented (i.e., both interim and annual periods). Taxes within the scope of EITF 06-3 are those that are imposed on and concurrent with a specific revenue-producing transaction. Taxes assessed on an entity's activities over a period of time are not within the scope of EITF 06-3. EITF 06-3 is effective for interim and annual reporting periods beginning after December 15, 2006 (March 31, 2007 for ACE) although earlier application is permitted.

      ACE does not anticipate that the adoption of EITF 06-3 will materially impact its disclosure requirements.

     FIN 48, "Accounting for Uncertainty in Income Taxes"

     On July 13, 2006, the FASB issued FIN 48, "Accounting for Uncertainty in Income Taxes" (FIN 48). FIN 48 clarifies the criteria for recognition of tax benefits in accordance with SFAS No. 109, "Accounting for Income Taxes," and prescribes a financial statement recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Specifically, it clarifies that an entity's tax benefits must be "more likely than not" of being sustained prior to recording the related tax benefit in the financial statements. If the position drops below the "more likely than not" standard, the benefit can no longer be

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recognized. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.

     FIN 48 is effective the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for ACE). ACE is in the process of evaluating the impact of FIN 48, but does not believe it will have a material impact on its financial condition, results of operations, and cash flow.

     SFAS No. 157, "Fair Value Measurements"

     In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" (SFAS No. 157) which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of this Statement will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements.

     SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (year ending December 31, 2008 for ACE).

     ACE is currently in the process of evaluating the impact of SFAS No. 157 on its financial condition, results of operations and cash flows.

     FSP AUG AIR-1, "Accounting for Planned Major Maintenance Activities"

     On September 8, 2006, the FASB issued FSP AUG AIR-1, which prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. FSP AUG AIR-1 is effective the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for ACE).

     ACE does not believe that the implementation of FSP AUG AIR-1 will have a material impact on its financial condition, results of operations and cash flows.

     "Staff Accounting Bulletin No. 108"

     On September 13, 2006, the SEC issued SAB No. 108 (SAB 108) which expresses the SEC staff's views on the process of quantifying financial statement misstatements. SAB 108 requires that registrants quantify the impact of correcting all misstatements, including both the carryover and reversing effects of prior year misstatements, on the current year financial statements by quantifying an error using both the rollover and iron curtain approaches and by evaluating the error measured under each approach. Under SAB 108, a registrant's financial statements would require adjustment when either approach results in a material misstatement, after considering all relevant quantitative and qualitative factors. Further, the SEC believes that a registrant's materiality assessment of an identified unadjusted error should quantify the effects of the identified unadjusted error on each financial statement and related financial statement disclosure. SAB 108 is effective for fiscal years endi ng on or after November 15, 2006.

     ACE implemented the guidance provided in SAB 108 during the year ended December 31, 2006.

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     SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115"

     On February 15, 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115" (SFAS No. 159) which permits entities to choose to elect to measure eligible financial instruments at fair value. The objective of SFAS No. 159 is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of SFAS No. 159 will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements.

     SFAS No.159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company's choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. SFAS No. 159 does not eliminate disclosure requirements included in other accounting standards.

     SFAS No. 159 applies to fiscal years beginning after November 15, 2007 (year ending December 31, 2008 for ACE), with early adoption permitted for an entity that has also elected to apply the provisions of SFAS No. 157, Fair Value Measurements.An entity is prohibited from retrospectively applying SFAS No. 159, unless it chooses early adoption. SFAS No. 159 also applies to eligible items existing at November 15, 2007 (or early adoption date). ACE is in the process of evaluating the impact of SFAS No. 159 on its financial condition, results of operations and cash flows.

(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 $9.6 million in 2006, $11.0 million in 2005, and $11.7 million in 2004. 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, 2006	Original   Cost	Accumulated Depreciation			Net         Book Value
	(Millions of dollars)
Generation	$     80.5		$  39.5	$     41.0
Distribution	1,188.1		359.3	828.8
Transmission	516.7		171.3	345.4
Construction work in progress	71.4		-	71.4
Non-operating and other property	156.6		59.7	96.9
Total	$2,013.3		$629.8	$1,383.5
Less: B.L. England assets held for sale	70.4		30.7	39.7
Total	$1,942.9		$599.1	$1,343.8
At December 31, 2005
Generation	$     77.4		$  29.4	$     48.0
Distribution	1,090.0		313.5	776.5
Transmission	534.4		188.3	346.1
Construction work in progress	56.8		-	56.8
Non-operating and other property	157.0		54.1	102.9
Total	$1,915.6		$585.3	$1,330.3

     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 Sheet includes its proportionate share of assets and liabilities related to jointly owned plant. ACE has ownership interests in 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 Earnings. 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, 2006 is shown below.

Jointly Owned Plant	Ownership Share	Plant in Service	Accumulated Depreciation	Construction Work in Progress
		(Millions of dollars)
Transmission Facilities	Various	$24.9	$14.6	$ -
Other Facilities	Various	1.1	.4	-
Total		$26.0	$15.0	$ -

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Asset Sales

     As discussed in Note (13), Discontinued Operations, on September 1, 2006, ACE completed the sale of its interests in the Keystone and Conemaugh generating facilities for approximately $177.0 million, which was subsequently decreased by $1.6 million based on a post-closing 60-day true-up for applicable items not known at the time of closing.

     Additionally, on February 8, 2007, ACE completed the sale of the B.L. England generating facility for a price of $9.0 million, subject to adjustment.

(6)  PENSIONS AND OTHER POSTRETIREMENT BENEFITS

     ACE accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan. For 2006, 2005, and 2004, ACE's allocated share of the pension and other postretirement net periodic benefit cost incurred by Pepco Holdings was approximately $14.3 million, $16.9 million, and $17.6 million, respectively. In 2006 and 2005, ACE contributed zero and $60 million, respectively to the Retirement Plan, and $6.6 million and $7.0 million, respectively to other postretirement benefit plans.  At December 31, 2006 and 2005, ACE's prepaid pension expense of $11.7 million and $8.0 million, and other postretirement benefit obligation of $27.1 million and $46.4 million, effectively represent assets and benefit obligations resulting from ACE's participation in the Pepco Holdings benefit plan.

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(7)  LONG-TERM DEBT

     Long-term debt outstanding as of December 31, 2006 and 2005 is presented below.

Type of Debt	Interest Rates	Maturity	2006		2005
			(Millions of dollars)
First Mortgage Bonds:
	6.18%-7.15%	2006-2008	$ 51.0	$116.0
	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
	5.60% (a)	2025	4.0	4.0
	Variable (a)(b)	2029	54.7	54.7
	5.80% (a)(b)	2034	120.0	120.0
	5.80% (a)(b)	2036	105.0	-
			467.2	427.2
Medium-Term Notes (unsecured)	7.52%	2007	15.0	15.0
Total long-term debt			482.2	442.2
Net unamortized discount			(.5)	(.5)
Current maturities of long-term debt			(16.0)	(65.0)
Total net long-term debt			$465.7	$376.7
Transition Bonds   ACE Funding:
	2.89%	2010	$  34.5	$  55.2
	2.89%	2011	23.0	31.3
	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
			494.5	523.5
Net unamortized discount			(.2)	(.2)
Current maturities of long-term debt			(29.9)	(29.0)
Total net long-term Transition Bonds   issued by ACE Funding			$464.4	$494.3

(a)

Represents a series of First Mortgage Bonds issued by ACE as collateral for an outstanding series of senior notes or tax-exempt bonds issued by or for the benefit of ACE. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or tax-exempt bonds are identical to the terms of the collateral First Mortgage Bonds by which it is secured. Payments of principal and interest on a series of senior notes or tax-exempt bonds satisfy the corresponding payment obligations on the related series of collateral First Mortgage Bonds. Because each series of senior notes and tax-exempt bonds and the series of collateral First Mortgage Bonds securing that series of senior notes or tax-exempt bonds effectively represents a single financial obligation, the senior notes and the tax-exempt bonds are not separately shown on the table.

(b)

Represents a series of First Mortgage Bonds issued by the indicated company as collateral for an outstanding series of senior notes that will, at such time as there are no First Mortgage Bonds of the issuing company outstanding (other than collateral First Mortgage Bonds securing payment of senior notes), cease to secure the corresponding series of senior notes and will be cancelled.

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     The outstanding First Mortgage Bonds issued by ACE are secured by a lien on substantially all of ACE's property, plant and equipment.

     ACE Funding was established in 2001 solely for the purpose of securitizing authorized portions of ACE's recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable transition bond charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). 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 principal amount of long-term debt including Transition Bonds outstanding at December 31, 2006, that will mature in each of 2007 through 2011 and thereafter is as follows: 2007-$45.9 million; 2008-$81.0 million; 2009-$32.2 million; 2010-$34.7 million; 2011-$35.4 million; and thereafter $747.4 million.

     ACE's long-term debt is subject to certain covenants. ACE is in compliance with all requirements.

SHORT-TERM DEBT

     ACE 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, 2006 and 2005 is as follows.

	2006	2005
	(Millions of dollars)
Commercial paper	$  1.2	$     -
Variable rate demand bonds	22.6	22.6
Total	$23.8	$22.6

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 a $500 million credit facility, described below under the heading "Credit Facility," shared with Potomac Electric Power Company (Pepco) and Delmarva Power & Light Company (DPL).

     ACE had $1.2 million of commercial paper outstanding at December 31, 2006 and no commercial paper outstanding at December 31, 2005. The weighted average interest rate for commercial paper issued during 2006 was 4.79%. The weighted average maturity for commercial paper issued during 2006 was four days.

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Variable Rate Demand Bonds

     Variable Rate Demand Bonds ("VRDB") are subject to repayment on the demand of the holders and for this reason are accounted for as short-term debt in accordance with GAAP. 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 the credit worthiness of the company and because the remarketing resets the interest rate to the then-current market rate. The company also may utilize one of the fixed rate/fixed term conversion options of the bonds to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, ACE views VRDB as a source of long-term financing. The VRDB outstanding in 2006 and 2005 mature in 2014 ($18.2 million) and 2017 ($4.4 million). The weighted average interest rate for VRDB was 3.39% and 2.47% during 2006 and 2005 respectively.

Credit Facility

     In April 2006, Pepco Holdings, Pepco, DPL and ACE extended their five-year credit agreement for one additional year from 2010 to 2011. The aggregate borrowing limit under the facility is $1.2 billion and the facility commitment expiration date is May 5, 2011. Pepco Holdings' credit limit under this agreement is $700 million.  The credit limit of each of Pepco, DPL and ACE is the lower of $300 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time under the agreement may not exceed $500 million. Under the terms of the credit agreement, the companies are entitled to request increases in the principal amount of available credit up to an aggregate increase of $300 million, with any such increase proportionately increasing the credit limit of each of the respective borrowers and the $300 million sublimits for each of Pepco, DPL and ACE.  The interest rate payable by the respective companies on utilized funds is determined by a pricing schedule with rates corresponding to the credit rating of the borrower. Any indebtedness incurred under the credit agreement would be unsecured.

     The credit agreement is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies also are permitted to use the facility to borrow funds for general corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties made by the borrower at the time the credit agreement was entered into also must be true at the time the facility is utilized, and the borrower must be in compliance with specified covenants, including the financial covenant described below. However, a material adverse change in the borrower's business, property, and results of operations or financial condition subsequent to the entry into the credit agreement is not a condition to the availability of credit under the facility. Among the covenants contained in the credit agreement are (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, (ii) a restriction on sales or other dispositions of assets, other than sales and dispositions permitted by the credit agreement, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than liens permitted by the credit agreement. The failure to satisfy any of the covenants or the occurrence of specified events that constitute an event of default could result in the acceleration of the repayment obligations of the borrower. The events of default include (i) the failure of any borrowing company or any of its significant subsidiaries to pay when due, or the acceleration of, certain indebtedness under other borrowing arrangements, (ii) certain

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bankruptcy events, judgments or decrees against any borrowing company or its significant subsidiaries, and (iii) a change in control (as defined in the credit agreement) of Pepco Holdings or the failure of Pepco Holdings to own all of the voting stock of Pepco, DPL and ACE. The agreement does not include any ratings triggers. There were no balances outstanding at December 31, 2006 and 2005.

(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 that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company 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.

     The provision for consolidated income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred income tax liabilities (assets) are shown below.

Provision for Consolidated Income Taxes

	For the Year Ended December 31,
	2006	2005	2004
	(Millions of dollars)
Operations
Current Tax Expense
Federal	$20.9	$104.7	$59.9
State and local	11.7	22.7	4.4
Total Current Tax Expense	32.6	127.4	64.3
Deferred Tax Expense (Benefit)
Federal	3.0	(73.1)	(25.1)
State	(1.2)	(12.1)	6.2
Investment tax credits	(1.4)	(1.0)	(4.7)
Total Deferred Tax Expense (Benefit)	.4	(86.2)	(23.6)
Total Income Tax Expense from Operations	$33.0	$41.2	$40.7
Discontinued Operations
Deferred Tax Expense
Federal	1.4	1.6	1.5
State	.4	.5	.4
Total Current Tax on Discontinued Operations	1.8	2.1	1.9
Extraordinary Item
Deferred Tax Expense
Federal	-	4.8	-
State and local	-	1.4	-
Total Deferred Tax on Extraordinary Item	-	6.2	-
Total Consolidated Income Tax Expense	$34.8	$49.5	$42.6

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Reconciliation of Consolidated Income Tax Expense

		For the Year Ended December 31,
		2006			2005			2004
		(Millions of dollars)
		Amount	Rate		Amount	Rate		Amount	Rate
Income Before Income Taxes, Discontinued    Operations and Extraordinary Item	$	93.1		$	92.3		$	99.5
Income tax at federal statutory rate	$	32.6	.35	$	32.3	.35	$	34.8	.35
Increases (decreases) resulting from
Depreciation		.4	-		.5	.01		2.0	.02
Asset removal costs		-	-		-	-		-	-
State income taxes, net of       federal effect		6.8	.07		6.8	.07		6.9	.07
Software amortization		-	-		-	-		-	-
Tax credits		(1.4)	(.01)		(1.0)	(.01)		(4.7)	(.05)
Change in estimates related to       prior year tax liabilities		(3.5)	(.04)		2.9	.03		(.4)	-
Other, net		(1.9)	(.02)		(.3)	-		2.1	.02
Total Consolidated Income Tax Expense    from Operations	$	33.0	.35	$	41.2	.45	$	40.7	.41

Components of Consolidated Deferred Income Tax Liabilities (Assets)

	As of December 31,
	2006	2005
	(Millions of dollars)
Deferred Tax Liabilities (Assets)
Depreciation and other book to tax basis differences	$482.2	$415.8
Deferred recoverable income taxes	6.3	5.6
Payment for termination of purchased power     contracts with NUGs	72.6	77.3
Electric restructuring liabilities	(58.6)	(21.7)
Fuel related	(41.4)	(24.6)
Deferred investment tax credits	(7.5)	(8.2)
Other	(25.2)	(22.1)
Total Deferred Tax Liabilities, net	428.4	422.1
Deferred tax asset included in Other Current Assets	12.6	10.4
Total Consolidated Deferred Tax Liabilities, net - non-current	$441.0	$432.5

     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 ACE'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, 2006 and 2005.

     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

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on ACE's property continues to be normalized over the remaining service lives of the related assets.

Taxes Other Than Income Taxes

     Taxes other than income taxes for each year are shown below. These amounts relate to the Power Delivery business and are recoverable through rates.

	2006	2005	2004
	(Millions of dollars)
Gross Receipts/Delivery	$21.1	$20.9	$18.4
Property	2.1	1.5	2.7
Environmental, Use and Other	(.3)	.2	(.7)
Total	$22.9	$22.6	$20.4

(9)  PREFERRED STOCK

     The preferred stock amounts outstanding as of December 31, 2006 and 2005 are as follows:

		Shares Outstanding			December 31,
Series	Redemption Price	2006	2005		2006	2005
				(Millions of dollars)
Redeemable Serial Preferred Stock
$100 per share par value
4.00%-5.00%	$100.00-$105.50	62,145	62,145		$6.2	$6.2

(10)  FAIR VALUES OF FINANCIAL INSTRUMENTS

     The estimated fair values of ACE's financial instruments at December 31, 2006 and 2005 are shown below.

	2006		2005
	Carrying Amount	Fair Value	Carrying Amount	Fair Value
	(Millions of dollars)
Long-term debt	$465.7	$480.6	$376.7	$402.3
Redeemable Serial Preferred Stock	$    6.2	$    4.4	$    6.2	$    4.4
Transition Bonds issued by ACE Funding	$464.4	$462.3	$494.3	$496.7

     The methods and assumptions below were used to estimate, at December 31, 2006 and 2005, the fair value of each class of financial instruments shown above for which it is practicable to estimate a value.

     The fair values of the Long-term Debt, which includes First Mortgage Bonds, Medium-Term Notes, and Transition Bonds issued by ACE Funding, 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.

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

     The carrying amounts of all other financial instruments in ACE's accompanying consolidated financial statements approximate fair value.

(11)  COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Rate Proceeding

     On May 15, 2006, ACE updated its FERC-approved formula transmission rates based on its FERC Form 1 data for 2005. This new rate of $14,155 per megawatt per year became effective on June 1, 2006. By operation of the formula rate process, the new rate incorporates true-ups from the 2005 formula rate that was effective June 1, 2005 and the new 2005 customer demand or peak load. Also, beginning in January 2007, the new rates will be applied to 2006 customer demand data, replacing the 2005 demand data that is currently used. This demand component is driven by ACE's prior year peak load. The net earnings impact from the network transmission rate changes year over year (2005 to 2006) is not expected to be material to ACE's overall financial condition, results of operations, or cash flows.

ACE Restructuring Deferral Proceeding

     Pursuant to orders issued by the NJBPU under the New Jersey Electric Discount and Energy Competition Act (EDECA), beginning August 1, 1999, ACE was obligated to provide BGS to retail electricity customers in its service territory who did not choose a competitive energy supplier. For the period August 1, 1999 through July 31, 2003, ACE's aggregate costs that it was allowed to recover from customers 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) related to ACE's Levelized Energy Adjustment Clause and ACE's Demand Side Management Programs. ACE established a regulatory asset in an amount equal to the balance of under-recovered costs.

     In August 2002, ACE filed a petition with the NJBPU for the recovery of approximately $176.4 million in actual and projected deferred costs relating to the provision of BGS and other restructuring related costs incurred by ACE over the four-year period August 1, 1999 through July 31, 2003, 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.

     In July 2004, the NJBPU issued a final order in the restructuring deferral proceeding confirming a July 2003 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 then pending base rate case for further consideration approximately $25.4 million of the deferred balance (the base rate case ended in a settlement approved by the NJBPU in May 2005, the result of which is that any net rate impact from the deferral account recoveries and credits in future years will depend in part

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on whether rates associated with other deferred accounts considered in the case continue to generate over-collections relative to costs), 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. Although ACE believes the record does not justify the level of disallowance imposed by the NJBPU in the final order, the $44.6 million of disallowed incurred costs were reserved during the years 1999 through 2003 (primarily 2003) through charges to earnings, primarily in the operating expense line item "deferred electric service costs," with a corresponding reduction in the regulatory asset balance sheet account. In August 2004, ACE filed a notice of appeal with respect to the July 2004 final order with the Appellate Division of the Superior Court of New Jersey (the Appellate Division), which hears appeals of the decisions of New Jersey administrative agencies, including the NJBPU. Briefs in the appeal were also filed by the Divi sion of the New Jersey Ratepayer Advocate and by Cogentrix Energy Inc., the co-owner of two cogeneration power plants with contracts to sell ACE approximately 397 megawatts of electricity, as cross-appellants between August 2005 and January 2006. The Appellate Division has not yet set the schedule for oral argument.

Divestiture Case

     In connection with the divestiture by ACE of its nuclear generating assets, the NJBPU in July 2000 preliminarily determined that the amount of stranded costs associated with the divested assets that ACE could recover from ratepayers should be reduced by approximately $94.5 million, representing the amount of the accumulated deferred federal income taxes (ADFIT) associated with the divested nuclear assets. However, due to uncertainty under federal tax law regarding whether the sharing of federal income tax benefits associated with the divested assets, including ADFIT, with ACE's customers would violate the normalization rules, ACE submitted a request to the Internal Revenue Service (IRS) for a Private Letter Ruling (PLR) to clarify the applicable law. The NJBPU has delayed its final determination of the amount of recoverable stranded costs until after the receipt of the PLR.

     On May 25, 2006, the IRS issued a PLR in which it stated that returning to ratepayers any of the unamortized ADFIT attributable to accelerated depreciation on the divested assets after the sale of the assets by means of a reduction of the amount of recoverable stranded costs would violate the normalization rules.

     On June 9, 2006, ACE submitted a letter to the NJBPU to request that the NJBPU conduct proceedings to finalize the determination of the stranded costs associated with the sale of ACE's nuclear assets in accordance with the PLR. ACE's request remains pending.

ACE Sale of Generating Assets

     On September 1, 2006, ACE completed the sale of its interests in the Keystone and Conemaugh generating facilities to Duquesne Light Holdings Inc. for approximately $177.0 million, which was subsequently decreased by $1.6 million based on a post-closing 60-day true-up for applicable items not known at the time of the closing. Approximately $81.3 million of the net gain from the sale has been used to offset the remaining regulatory asset balance, which ACE has been recovering in rates, and approximately $49.8 million of the net gain is being returned to ratepayers over a 33-month period as a credit on their bills, which began with the October 2006 billing month. The balance to be repaid to customers is $48.4 million as of December 31, 2006.

     On February 8, 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy

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Investments, LLC, for a price of $9.0 million, after adjustment for, among other things, variances in the value of fuel and material inventories at the time of closing, plant operating capacity, the value of certain benefits for transferred employees and the actual closing date. The purchase price will be further adjusted based on a post-closing 60-day true-up for applicable items not known at the time of the closing. In addition, RC Cape May and ACE have agreed to arbitration concerning whether RC Cape May must pay to ACE, as part of the purchase price, an additional $3.1 million remaining in dispute. RC Cape May also assumed certain liabilities associated with the B.L. England generating station, including substantially all environmental liabilities. This transaction is further described below under the heading "Environmental Litigation."

     The sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized. ACE anticipates that approximately $9 to $10 million of additional regulatory assets related to B.L. England may, subject to NJBPU approval, be eligible for recovery as stranded costs. The emission allowance credits associated with B. L. England will be monetized for the benefit of ACE's ratepayers pursuant to the NJBPU order approving the sale. Net proceeds from the sale of the plant and monetization of the emission allowance credits, which will be determined after the sale upon resolution of certain adjustments, will be credited to ACE's ratepayers in accordance with the requirements of EDECA and NJBPU orders.

Environmental Litigation

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

     In November 1991, the New Jersey Department of Environmental Protection (NJDEP) identified ACE as a potentially responsible party (PRP) at the Delilah Road Landfill site in Egg Harbor Township, New Jersey. In 1993, ACE, along with other PRPs, signed an administrative consent order (ACO) 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. Positive results of groundwater monitoring events have resulted in a reduced level of groundwater monitoring. In August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site. Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years and to continue groundwater mon itoring.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 anticipates that its share of additional cost associated with this site will be approximately $555,000 to $600,000. ACE believes that its liability for post-remedy operation and

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maintenance costs will not have a material adverse effect on its financial position, results of operations or cash flows.

     On January 24, 2006, PHI, Conectiv and ACE entered into an ACO with NJDEP and the Attorney General of New Jersey resolving (i) New Jersey's claim for alleged violations of the federal Clean Air Act (CAA) and (ii) the NJDEP's concerns regarding ACE's compliance with New Source Review requirements of the CAA and Air Pollution Control Act requirements with respect to the B.L. England generating facility and various other environmental issues relating to ACE and affiliate facilities in New Jersey. See Item 1 "Business -- Environmental Matters -- Air Quality Regulation."

IRS Mixed Service Cost Issue

     During 2001, ACE changed its method of accounting with respect to capitalizable construction costs for income tax purposes. The change allowed ACE to accelerate the deduction of certain expenses that were previously capitalized and depreciated. Through December 31, 2005, these accelerated deductions generated incremental tax cash flow benefits of approximately $49 million, primarily attributable to its 2001 tax returns.

     On August 2, 2005, the Treasury Department released regulations that, if adopted in their current form, would require DPL to change its method of accounting with respect to capitalizable construction costs for income tax purposes for future tax periods beginning in 2005. Based on those regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believes will be acceptable to the IRS.

     On the same day that the new regulations were released, the IRS issued Revenue Ruling 2005-53, which is intended to limit the ability of certain taxpayers to utilize the method of accounting for income tax purposes they utilized on their tax returns for 2004 and prior years with respect to capitalizable construction costs. In line with this Revenue Ruling, the IRS revenue agent's report for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that ACE had claimed on those returns by requiring it to capitalize and depreciate certain expenses rather than treat such expenses as current deductions. PHI's protest of the IRS adjustments is among the unresolved audit matters relating to the 2001 and 2002 audits pending before the Appeals Office.

     In February 2006, PHI paid approximately $121 million of taxes to cover the amount of taxes that management estimated to be payable based on the method of tax accounting that PHI, pursuant to the proposed regulations, has adopted on its 2005 tax return. However, if the IRS is successful in requiring ACE to capitalize and depreciate construction costs that result in a tax and interest assessment greater than management's estimate of $121 million, PHI will be required to pay additional taxes and interest only to the extent these adjustments exceed the $121 million payment made in February 2006.

Contractual Obligations

     As of December 31, 2006, ACE's contractual obligations under non-derivative fuel and power purchase contracts (excluding BGS supplier load commitments) were $287.6 million in 2007, $556.4 million in 2008 to 2009, $499.9 million in 2010 to 2011, and $2,750.9 million in 2012 and thereafter.

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(12)  RELATED PARTY TRANSACTIONS

     PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including ACE. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries' share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to ACE for the years ended December 31, 2006, 2005 and 2004 were $79.3 million, $82.2 million and $86.3 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 Statements of Earnings:

	For the Year Ended December 31,
	2006	2005	2004
(Expense) Income	(Millions of dollars)
Purchased power from Conectiv Energy Supply (a)	$(89.0)	$(85.8)	$(41.6)
Meter reading services provided by   Millennium Account Services LLC (b)	(3.8)	(3.7)	(3.7)

(a)	Included in fuel and purchased energy.
(b)	Included in other operation and maintenance.

     As of December 31, 2006 and 2005, ACE had the following balances due (to)/from related parties:

	2006	2005
Asset (Liability)	(Millions of dollars)
Receivable from Related Party (current)   PHI Parent	$  8.4	$       -
Payable to Related Party (current)
PHI Service Company	(28.7)	(7.2)
Conectiv Energy Supply	(6.3)	(30.9)
PHI Parent	-	(.1)
The items listed above are included in the "Accounts payable to associated companies" balance on the Consolidated Balance Sheet of $27.3 million and $38.3 million at December 31, 2006 and 2005, respectively.
Money Pool Balance with Pepco Holdings   (included in cash and cash equivalents)	-	4.0
Money Pool Interest Receivable (included in accounts receivable)	$     -	$      .5

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(13)  DISCONTINUED OPERATIONS

     As discussed in Note (11), "Commitments and Contingencies," herein, in May 2005, ACE announced that it would auction its electric generation assets, consisting of its ownership interests in the Keystone and Conemaugh generating facilities and its B.L. England generating facility. On September 1, 2006, ACE completed the sale of its interests in the Keystone and Conemaugh generating facilities to Duquesne Light Holdings Inc. for approximately $177.0 million, which was subsequently decreased by $1.6 million based on a post-closing 60-day true-up for applicable items not known at the time of the closing. Approximately $81.3 million of the net gain from the sale has been used to offset the remaining regulatory asset balance, which ACE has been recovering in rates, and approximately $49.8 million of the net gain is being returned to ratepayers over a 33-month period as a credit on their bills, which began during the October 2006 billing period. The balance to be repaid to custom ers is $48.4 million as of December 31, 2006.

     Additionally, on February 8, 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May for a price of $9.0 million, after adjustment for, among other things, variances in the value of fuel and material inventories at the time of closing, plant operating capacity, the value of certain benefits for transferred employees and the actual closing date. The purchase price will be further adjusted based on a post-closing 60-day true-up for applicable items not known at the time of the closing. In addition, RC Cape May and ACE have agreed to arbitration concerning whether RC Cape May must pay to ACE, as part of the purchase price, an additional $3.1 million remaining in dispute. RC Cape May also assumed certain liabilities associated with the B.L. England generating station, including substantially all environmental liabilities. Not included in the sale are certain SO₂ and NOx allowances, including those covered by the ACO entered into by ACE o n January 24, 2006, as described above in Item 1 "Business -- Environmental Matters -- Air Quality Regulation." On October 31, 2006, ACE, RC Cape May and NJDEP signed an amendment to the ACO, pursuant to which RC Cape May assumed from ACE, upon closing of the sale, certain obligations under the ACO with respect to the B. L. England facility. In addition, among other conditions, the sale required the entry by RC Cape May into a remediation agreement with NJDEP and NJDEP approval of the transfer of certain environmental permits from ACE to the buyer.

     The sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized. ACE anticipates that approximately $9 million to $10 million of additional regulatory assets related to B.L. England may, subject to NJBPU approval, be eligible for recovery as stranded costs. The emission allowance credits associated with B.L. England will be monetized for the benefit of ACE's ratepayers pursuant to the NJBPU order approving the sale. Net proceeds from the sale of the plant and monetization of the emission allowance credits, which will be determined after the sale upon resolution of certain adjustments, will be credited to ACE's ratepayers in accordance with the requirements of EDECA and NJBPU orders.

     B.L. England comprised a significant component of ACE's generation operations and its potential sale required "discontinued operations" presentation under SFAS No. 144, "Accounting for the Impairment or Disposal of Long Lived Assets," on ACE's Consolidated Statements of Earnings for the years ended December 31, 2006, 2005 and 2004. The operations of Keystone and Conemaugh are also reflected as "discontinued operations" for each period presented. Additionally, B.L. England's assets and liabilities are reflected as "held for sale" on ACE's Consolidated Balance Sheet at December 31, 2006.

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     The following table summarizes information related to the discontinued operations presentation (millions of dollars):

	2006	2005	2004
Operating Revenue	$113.7	$170.3	$119.9
Income Before Income Tax Expense and Extraordinary Item	$   4.4	$    5.2	$   4.8
Net Income	$   2.6	$   3.1	$   2.9

(14) EXTRAORDINARY ITEMS

     On April 19, 2005, ACE, the staff of the NJBPU, the New Jersey Ratepayer Advocate, and active intervenor parties agreed on a settlement in ACE's electric distribution rate case. As a result of this settlement, ACE reversed $15.2 million in accruals related to certain deferred costs that are now deemed recoverable. The after-tax credit to income of $9.0 million is classified as an extraordinary gain in the 2005 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.

	2006
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Total
	(Millions of dollars)
Total Operating Revenue	$301.5	$299.0	$479.7	$293.1	$1,373.3
Total Operating Expenses	277.7	256.9	417.8	268.7	1,221.1
Operating Income	23.8	42.1	61.9	24.4	152.2
Other Expenses	(16.6)	(14.6)	(14.2)	(13.7)	(59.1)
Income Before Income Taxes	7.2	27.5	47.7	10.7	93.1
Income Tax Expense	1.7	7.8	18.5	5.0	33.0
Income From Continuing Operations	5.5	19.7	29.2	5.7	60.1
Discontinued Operations, net of tax	.8	.8	.7	.3	2.6
Net Income	6.3	20.5	29.9	6.0	62.7
Dividends on Preferred Stock	.1	.1	.1	-	.3
Earnings Available for Common Stock	$  6.2	$ 20.4	$ 29.8	$  6.0	$ 62.4

	2005
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Total
	(Millions of dollars)
Total Operating Revenue	$279.2	$262.9	$480.0	$328.0	$1,350.1
Total Operating Expenses	258.8	231.0	407.8	309.2	1,206.8
Operating Income	20.4	31.9	72.2	18.8	143.3
Other Expenses	(12.3)	(12.6)	(13.3)	(12.8)	(51.0)
Income Before Income Taxes	8.1	19.3	58.9	6.0	92.3
Income Tax Expense	3.5	7.7	26.1 (b)	3.9 (c)	41.2
Income From Continuing Operations	4.6	11.6	32.8	2.1	51.1
Discontinued Operations, net of tax	.7	.7	.9	.8	3.1
Income Before Extraordinary Item	5.3	12.3	33.7	2.9	54.2
Extraordinary Item (a)	9.0	-	-	-	9.0
Net Income	14.3	12.3	33.7	2.9	63.2
Dividends on Preferred Stock	.1	.1	.1	-	.3
Earnings Available for   Common Stock	$ 14.2	$ 12.2	$ 33.6	$   2.9	$   62.9

NOTE:	Sales of electric energy are seasonal and, accordingly, comparisons by quarter within a year are not meaningful.
(a)	Relates to ACE's electric distribution rate case settlement that was accounted for in the first quarter of 2005. This resulted in ACE's reversal of $9.0 million in after-tax accruals related to certain deferred costs that are now deemed recoverable. This amount is classified as an extraordinary gain since the original accrual was part of an extraordinary charge in conjunction with the accounting for competitive restructuring in 1999.
(b)	Includes $1.7 million in income tax expense related to the mixed service cost issue under IRS Ruling 2005-53.
(c)	Includes $.3 million in income tax expense related to the mixed service cost issue under IRS Ruling 2005-53.

(16)  SUBSEQUENT EVENT

     On February 8, 2007, ACE completed the sale of the B.L. England generating facility for a price of $9.0 million, subject to adjustment.

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THIS PAGE LEFT INTENTIONALLY BLANK.

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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, 2006, and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco Holdings have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to Pepco Holdings and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended (the Exchange Act) (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as a ppropriate to allow timely decisions 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 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 of this Form 10-K.

Changes in Internal Control Over Financial Reporting

     During the quarter ended December 31, 2006, 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.

     In October 2006, Pepco commenced outsourcing its cash remittance processing to a third party vendor, which already provides such service to ACE and DPL.

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, 2006, and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco

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have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to Pepco that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

     During the quarter ended December 31, 2006, 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.

     In October 2006, Pepco commenced outsourcing its cash remittance processing to a third party vendor, which already provides such service to ACE and DPL.

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, 2006, and, based upon this evaluation, the chief executive officer and the chief financial officer of DPL have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to DPL that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

     During the quarter ended December 31, 2006, 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, 2006, and, based upon this evaluation, the chief executive officer and the chief financial officer of ACE have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to ACE and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

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Changes in Internal Control Over Financial Reporting

     During the quarter ended December 31, 2006, 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.

     None.

Potomac Electric Power Company

     None.

Delmarva Power & Light Company

     None

Atlantic City Electric Company

     None

Part III

Item 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Pepco Holdings, Inc.

     Other than as set forth below, the information required by this Item 10 with regard to PHI is incorporated herein by reference to PHI's definitive proxy statement for the 2007 Annual Meeting of Shareholders to be filed with the SEC on or about March 29, 2007 (excluding the information under the caption "Audit Committee Report").

Executive Officers of PHI

     The names of the executive officers of PHI and their ages and the positions they held as of February 15, 2007 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	62	Chairman of the Board, President and Chief Executive Officer 5/04 - Present (1)
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William T. Torgerson	62	Vice Chairman and General Counsel 6/03 - Present (2)
Thomas S. Shaw	59	Executive Vice President and Chief Operating Officer 8/02 - Present (3)
Joseph M. Rigby	50	Senior Vice President and Chief Financial Officer 5/04 - Present (4)
Beverly L. Perry	59	Senior Vice President 10/02 - Present (5)
Ronald K. Clark	51	Vice President and Controller 8/05 - Present (6)
John U. Huffman	47	President-6/06 - Presentand Chief Operating Officer, Pepco Energy Services, Inc. - 4/06 - Present (7)
David M. Velazquez	47	President- 6/06 - Present and Chief Executive Officer, Conectiv Energy Holding Company - 1/07 - Present (8)

(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 Chairman of Pepco since May 2004 and was Chief Executive Officer from August 2002 until October 2005. Since May 2004, he has also been Chairman of DPL and ACE. He was President and Chief Operating Officer of Pepco from January 2001 until August 2002.
(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.
(3)	Mr. Shaw has served as President and Chief Executive Officer of Pepco and ACE since January 1, 2007 and has served as President of DPL since May 2004 and Chief Executive Officer of DPL since August 2002. Mr. Shaw has served as President and Chief Operating Officer of Conectiv since September 2000. He was also Executive Vice President of DPL from 1998 until 2002.
(4)	Mr. Rigby has been Senior Vice President of PHI since August 2002 and has been Chief Financial Officer of PHI since May 2004. Mr. Rigby was President of ACE from July 2001 until May 2004 and 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.
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(5)	Ms. Perry served as a Vice President of Pepco from April 1999 to August 2002.
(6)	Mr. Clark has been employed by PHI since June 2005 and has also served as Vice President and Controller of Pepco and DPL and Controller of ACE since August 2005. From July 2004 until June 2005, he was Vice President, Financial Reporting and Policy for MCI, Inc., a telecommunications company not affiliated with PHI. From June 2002 until December 2003, Mr. Clark served as Vice President, Controller and Chief Accounting Officer of Allegheny Energy, Inc., an energy company not affiliated with PHI. From January 2002 until May 2002, he was Controller of Lockheed Martin Global Telecommunications, a business segment of Lockheed Martin Corporation, a company engaged in the sale of technology systems, products and services, not affiliated with PHI.
(7)	Since June 2003, Mr. Huffman has been employed by PES in the following capacities: (a) Chief Operating Officer from April 2006 to June 2006, (b) Senior Vice President, February 2005 to March 2006 and (c) Vice President from June 2003 to February 2005. From June 2000 to May 2003, Mr. Huffman was Chief Operating Officer of ACN Energy, Inc, a retail electricity and natural gas provider which is not affiliated with PHI.
(8)	Mr. Velazquez served as Chief Operating Officer of Conectiv Energy Holding Company from June 2006 to December 2006. He served as a Vice President of PHI from February 2005 to June 2006 and as Chief Risk Officer of PHI from August 2005 to June 2006. From July 2001 to February 2005, he served as a Vice President of Conectiv Energy Supply, Inc., an affiliate of PHI.

     The PHI executive officers are elected annually and serve until their respective successors have been elected and qualified or their earlier resignation or removal.

     INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, 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 PHI's definitive proxy statement for the 2007 Annual Meeting of Shareholders to be filed with the SEC on or about March 29, 2007 (excluding the information under the caption "Compensation Committee Report").

     INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, 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 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
               MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Pepco Holdings, Inc.

     Other than as set forth below, the information required by this Item 12 with regard to PHI is incorporated herein by reference to PHI's definitive proxy statement for the 2007 Annual Meeting of Shareholders to be filed with the SEC on or about March 29, 2007.

     The following table provides information as of December 31, 2006, with respect to the shares of PHI's common stock that may be issued under PHI's existing equity compensation plans.

Equity Compensation Plans Information
Plan Category	(a) Number of Securities to be Issued Upon Exercise of Outstanding Options	(b) Weighted-Average Exercise Price of Outstanding Options	(c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
Equity Compensation Plans Approved by Shareholders (1)	(2)	(2)	9,626,494
Equity Compensation Plans Not Approved by Shareholders (3)	0	0	496,628
Total	-	-	10,123,122

(1) Consists solely of the Pepco Holdings, Inc. Long-Term Incentive Plan.

(2) In connection with the acquisition by Pepco of Conectiv (i) outstanding options granted under the Potomac Electric Power Company Long-Term Incentive Plan were converted into options to purchase shares of PHI common stock and (ii) options granted under the Conectiv Incentive Compensation Plan were converted into options to purchase shares of PHI common stock. As of December 31, 2006, options to purchase an aggregate of 1,130,724 shares of PHI common stock, having a weighted average exercise price of $22.5099, were outstanding.

(3) On January 1, 2005, the PHI Non-Management Directors Compensation Plan (the Directors Compensation Plan) became effective, pursuant to which 500,000 shares of PHI common stock became available for future issuance. Under the Directors Compensation Plan, each director who is not an employee of PHI or any of its subsidiaries ("non-management director") is entitled to elect to receive his or her annual retainer, retainer for service as a committee chairman, if any, and meeting fees in: (i) cash, (ii) shares of PHI's common stock, (iii) a credit to an account for the director established under PHI's Executive and Director Deferred Compensation Plan or (iv) any combination thereof. The Directors Compensation Plan expires on December 31, 2014 unless terminated earlier by the Board of Directors.

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     INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, 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 AND
               DIRECTOR INDEPENDENCE

Pepco Holdings, Inc.

     The information required by this Item 13 with regard to PHI is incorporated herein by reference to PHI's definitive proxy statement for the 2007 Annual Meeting of Shareholders to be filed with the SEC on or about March 29, 2007.

     INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, 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 ACCOUNTING FEES AND SERVICES

Pepco Holdings, Inc., Pepco, DPL and ACE

Audit Fees

     The aggregate fees billed by PricewaterhouseCoopers LLP for professional services rendered for the audit of the annual financial statements of Pepco Holdings and its subsidiary reporting companies for the 2006 and 2005 fiscal years and reviews of the financial statements included in the 2006 and 2005 Forms 10-Q of PHI and its subsidiary reporting companies were $5,515,127 and $5,407,413, respectively. The amount for 2005 includes $55,330 for the 2005 audit that was billed after the 2005 amount was disclosed in Pepco Holdings' proxy statement for the 2006 Annual Meeting.

Audit-Related Fees

     The aggregate fees billed by PricewaterhouseCoopers LLP for audit-related services rendered for the 2006 and 2005 fiscal years were $19,736 and $214,053, respectively. These services consist of employee benefit plan audits, accounting consultations, internal control reviews, computer systems post-implementation reviews and attest services for financial reporting not required by statute or regulation. The amount for 2005 includes $44,000 for the 2005 employee benefit plan audit that was billed after the 2006 Pepco Holdings proxy statement was filed.

Tax Fees

     The aggregate fees billed by PricewaterhouseCoopers LLP for tax services rendered for the 2006 and 2005 fiscal years were $86,160 and $8,400, respectively. These services consisted of tax compliance, tax advice and tax planning.

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All Other Fees

     The aggregate fees billed by PricewaterhouseCoopers LLP for all other services other than those covered under "Audit Fees," "Audit-Related Fees" and "Tax Fees" for the 2006 and 2005 fiscal years were $20,419and $3,000, respectively, which represents the costs of training and technical materials provided by PricewaterhouseCoopers LLP.

      All of the services described in "Audit Fees," "Audit-Related Fees," "Tax Fees" and "All Other Fees" were approved in advance by the Audit Committee, in accordance with the Audit Committee Policy on the Approval of Services by the Independent Auditor which is attached as Annex A to Pepco Holdings' definitive proxy statement for the 2007 Annual Meeting of Shareholders to be filed with the SEC on or about March 29, 2007.

Part IV

Item 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)  Documents List

1.   FINANCIAL STATEMENTS

     The financial statements filed as part of this report consist of:

            The financial statements of each registrant set forth in Item 8. "Financial Statements and Supplemental Data."

2.   FINANCIAL STATEMENT SCHEDULES

     The financial statement schedules specified by Regulation S-X, other than those listed below, are omitted because either they are not applicable or the required information is presented in the financial statements 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	338	N/A	N/A	N/A
Schedule II, Valuation and   Qualifying Accounts	341	341	342	342

337

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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,
	2006	2005	2004
	(Millions of dollars, except share data)
OPERATING REVENUE	$    -	$    -	$    -
OPERATING EXPENSES
Depreciation and amortization	-	2.1	3.8
Other operation and maintenance	2.8	5.4	2.5
Total operating expenses	2.8	7.5	6.3
OPERATING LOSS	(2.8)	(7.5)	(6.3)
OTHER INCOME (EXPENSES)
Interest and dividend income	.1	.1	.5
Interest expense	(83.3)	(77.1)	(97.6)
Income from equity investments	298.9	406.5	317.8
Total other income	215.7	329.5	220.7
INCOME BEFORE INCOME TAXES AND   EXTRAORDINARY ITEM	212.9	322.0	214.4
INCOME TAX BENEFIT	(35.4)	(40.2)	(46.2)
INCOME BEFORE EXTRAORDINARY ITEM	248.3	362.2	260.6
EXTRAORDINARY ITEM (net of income taxes of   $6.2 million)	-	9.0	-
NET INCOME	$248.3	$371.2	$260.6
EARNINGS PER SHARE
Basic and diluted before extraordinary item	$ 1.30	$ 1.91	$ 1.48
Basic and diluted extraordinary item	-	.05	-
Basic and diluted earnings     per share of common stock	$ 1.30	$ 1.96	$ 1.48

The accompanying Notes are an integral part of these financial statements.

338

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PEPCO HOLDINGS, INC. (Parent Company)
BALANCE SHEETS
	As of December 31,
	2006	2005
	(Millions of dollars, except share data)
ASSETS
Current Assets
Cash and cash equivalents	$    96.4	$    43.2
Prepaid and other	16.4	29.1
	112.8	72.3
Investments and Other Assets
Notes receivable from subsidiary companies	934.3	1,137.2
Investment in consolidated companies	4,763.5	4,590.8
Other	31.3	44.7
	5,729.1	5,772.7
Property, Plant and Equipment
Property, plant, and equipment	-	13.7
Accumulated depreciation	-	(13.7)
Net plant in service	-	-
Total Assets	$5,841.9	$5,845.0
CAPITALIZATION AND LIABILITIES
Current Liabilities
Short-term debt	$   536.0	$   300.0
Accounts payable	3.4	4.9
Interest and taxes accrued	41.9	7.4
	581.3	312.3
Long-Term Debt	1,648.4	1,948.6
Commitments and Contingencies
Capitalization
Common stock, $.01 par value;      authorized 400,000,000 shares; issued      191,932,445 and 189,817,723 shares, respectively	1.9	1.9
Premium on stock and other capital      contributions	2,645.0	2,586.3
Accumulated other comprehensive loss	(103.4)	(22.8)
Retained earnings	1,068.7	1,018.7
Total common stockholders' equity	3,612.2	3,584.1
Total Capitalization and Liabilities	$5,841.9	$5,845.0

The accompanying Notes are an integral part of these financial statements.

339

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PEPCO HOLDINGS, INC. (Parent Company)
STATEMENTS OF CASH FLOWS
	For the Year Ended December 31,
	2006	2005	2004
	(Millions of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 248.3	$ 371.2	$ 260.6
Adjustments to reconcile net income to net     cash provided by operating activities:
Depreciation and amortization	2.7	6.6	8.5
Distributions from related parties          (less than) in excess of earnings	(200.7)	(344.1)	(188.6)
Extraordinary item	-	(15.2)	-
Deferred income taxes, net	34.6	3.8	20.7
Net change in:
Prepaid and other	6.0	(1.0)	(.1)
Accounts payable	(.1)	.7	2.4
Interest and taxes	(33.5)	.5	(60.5)
Other, net	11.0	12.1	14.3
Net cash provided by operating activities	68.3	34.6	57.3
CASH FLOWS FROM INVESTING ACTIVITIES
Net investment in property, plant and equipment	-	-	-
Net cash used by investing activities	-	-	-
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid on common stock	(198.3)	(188.9)	(176.0)
Common stock issued to the Dividend Reinvestment Plan	29.8	27.5	29.2
Issuance of common stock	17.0	5.7	288.8
Issuance of long-term debt	200.0	250.0	-
Reacquisition of long-term debt	(300.0)	-	(200.0)
Decrease (increase) in notes receivable from          associated companies	202.9	(49.1)	(93.2)
Issuances (repayments) of short-term debt, net	36.0	(128.6)	128.6
Costs of issuances and refinancings	(2.1)	(3.2)	(12.7)
Other financing activities	(.4)	(.3)	-
Net cash used by financing activities	(15.1)	(86.9)	(35.3)
Net change in cash and cash equivalents	53.2	(52.3)	22.0
Beginning of year cash and cash equivalents	43.2	95.5	73.5
End of year cash and cash equivalents	$  96.4	$  43.2	$  95.5

The accompanying Notes are an integral part of these financial statements.

NOTES TO FINANCIAL INFORMATION

     These condensed financial statements represent the financial information for Pepco Holdings, Inc. (Parent Company).

     For information concerning PHI's long-term debt obligations, see Note (7) "Debt" to the consolidated financial statements of Pepco Holdings included in Item 8 of Part II.

     For information concerning PHI's material contingencies and guarantees, see Note (12) "Commitments and Contingencies" to the consolidated financial statements of Pepco Holdings included in Item 8.

    The Parent Company's majority owned subsidiaries are recorded using the equity method of accounting.

340

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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 Beginning of Period	Charged to Costs and Expenses	Charged to Other Accounts (a)	Deductions(b)	Balance at End of Period
	(Millions of dollars)
Year Ended December 31, 2006   Allowance for uncollectible     accounts - customer and     other accounts receivable	$40.6	$19.9	$1.4	$(26.1)	$35.8
Year Ended December 31, 2005   Allowance for uncollectible     accounts - customer and     other accounts receivable	$43.7	$21.4	$2.0	$(26.5)	$40.6
Year Ended December 31, 2004   Allowance for uncollectible     accounts - customer and     other accounts receivable	$43.5	$23.2	$ .8	$(23.8)	$43.7

(a)	Collection of accounts previously written off.
(b)	Uncollectible accounts written off.

Potomac Electric Power Company
Col. A	Col. B	Col. C		Col. D	Col. E
		Additions
Description	Balance at Beginning of Period	Charged to Costs and Expenses	Charged to Other Accounts (a)	Deductions(b)	Balance at End of Period
	(Millions of dollars)
Year Ended December 31, 2006   Allowance for uncollectible     accounts - customer and     other accounts receivable	$14.1	$11.0	$1.4	$(9.1)	$17.4
Year Ended December 31, 2005   Allowance for uncollectible     accounts - customer and     other accounts receivable	$20.1	$   .9	$2.0	$(8.9)	$14.1
Year Ended December 31, 2004   Allowance for uncollectible     accounts - customer and     other accounts receivable	$18.4	$ 7.8	$ .8	$(6.9)	$20.1

(a)  Collection of accounts previously written off.

(b)  Uncollectible accounts written off.

341

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Delmarva Power & Light Company
Col. A	Col. B	Col. C		Col. D	Col. E
		Additions
Description	Balance at Beginning of Period	Charged to Costs and Expenses	Charged to Other Accounts (a)	Deductions(b)	Balance at End of Period
	(Millions of dollars)
Year Ended December 31, 2006   Allowance for uncollectible     accounts - customer and     other accounts receivable	$ 9.2	$4.3	$-	$(5.7)	$ 7.8
Year Ended December 31, 2005   Allowance for uncollectible     accounts - customer and     other accounts receivable	$ 8.7	$6.8	-	$(6.3)	$ 9.2
Year Ended December 31, 2004   Allowance for uncollectible     accounts - customer and     other accounts receivable	$10.1	$6.3	-	$(7.7)	$ 8.7

(a)  Collection of accounts previously written off.

(b)  Uncollectible accounts written off.

Atlantic City Electric Company
Col. A	Col. B	Col. C		Col. D	Col. E
		Additions
Description	Balance at Beginning of Period	Charged to Costs and Expenses	Charged to Other Accounts (a)	Deductions(b)	Balance at End of Period
	(Millions of dollars)
Year Ended December 31, 2006   Allowance for uncollectible     accounts - customer and     other accounts receivable	$5.2	$5.0	$-	$(4.7)	$5.5
Year Ended December 31, 2005   Allowance for uncollectible     accounts - customer and     other accounts receivable	$4.5	$5.5	-	$(4.8)	$5.2
Year Ended December 31, 2004   Allowance for uncollectible     accounts - customer and     other accounts receivable	$5.3	$4.7	-	$(5.5)	$4.5

(a)  Collection of accounts previously written off.

(b)  Uncollectible accounts written off.

342

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3.     Exhibits required by Item 601 of SEC Regulation S-K.

EXHIBITS

     The documents listed below are being filed herewith or have previously been filed and are incorporated herein by reference from the documents indicated and made a part hereof.

Exhibit   No.	Registrant(s)	Description of Exhibit	Reference
3.1	PHI	Restated Certificate of Incorporation (filed in Delaware 6/2/2005)	Exh. 3.1 to PHI's Form 10-K, 3/13/06.
3.2	Pepco	Restated Articles of Incorporation and Articles of Restatement (as filed in the District of Columbia)	Exh. 3.1 to Pepco's Form 10-Q, 5/5/06.
3.3	DPL	Articles of Restatement of Certificate and Articles of Incorporation (filed in Delaware and Virginia 02/22/07)	Filed herewith.
3.4	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.
3.5	PHI	Bylaws	Exh. 3 to PHI's Form 8-K, 1/30/06.
3.6	Pepco	By-Laws	Exh. 3.1 to Pepco's Form 10-Q, 5/5/06.
3.7	DPL	Bylaws	Exh. 3.2.1 to Form 10-Q 5/9/05.
3.8	ACE	Bylaws	Exh. 3.2.2 to Form 10-Q 5/9/05.
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.

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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.
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.

344

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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.
June 17, 1981	Exh. 2 to Amendment No. 1 to Form 8-A, 6/18/81.
November 1, 1985	Exh. 2B to Form 8-A, 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.

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		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.
		September 30, 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. 33-61379, 7/28/95.
		October 2, 1997	Exh. 4 to Pepco's Form 10-K, 3/26/98.
		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.
		May 24, 2005	Exh. 4.2 to Pepco's Form 8-K, 5/26/05.
		April 1, 2006	Exh. 4.1 to Pepco's Form 8-K, 4/17/06.
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	PHI Pepco	Senior Note Indenture dated November 17, 2003 between Pepco and The Bank of New York	Exh. 4.2 to Pepco's Form 8-K, 11/21/03.

346

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4.4	PHI DPL	Mortgage and Deed of Trust of Delaware Power & Light Company to The Bank of New York Trust Company, N.A. Trustee, (ultimate successor to the New York Trust Company) 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.
		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.

347

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4.5	PHI DPL	Indenture between DPL and The Bank of New York Trust Company, N.A. (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 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 -
		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.

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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.
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.

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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.
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	Exh. 4(a) to ACE's Form 10-Q, 11/12/93.
September 1, 1993	Exh. 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.
March 8, 2006	Exh. 4 to ACE's Form 8-K, 3/17/06.

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4.7	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.
4.8	PHI ACE	Senior Note 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.
4.9	PHI ACE	Indenture dated as of December 19, 2002 between Atlantic City Electric Transition Funding LLC (ACE Funding) and The Bank of New York	Exh. 4.1 to ACE Funding's Form 8-K, 12/23/02.
4.10	PHI ACE	2002-1 Series Supplement dated as of December 19, 2002 between ACE Funding and The Bank of New York	Exh. 4.2 to ACE Funding's Form 8-K, 12/23/02.
4.11	PHI ACE	2003-1 Series Supplement dated as of December 23, 2003 between ACE Funding and The Bank of New York	Exh. 4.2 to ACE Funding's Form 8-K, 12/23/03.
4.12	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.
4.13	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.
4.14	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.
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 Thomas S. Shaw*	Exh. 10.5 to PHI's Form 10-Q, 8/9/02.
10.4	PHI	Employment Agreement of Eddie R. Mayberry*	Exh. 10.6 to PHI's Form 10-Q, 8/9/02.
10.5	PHI	Employment Agreement of Joseph M. Rigby*	Exh. 10.8 to PHI's Form 10-Q, 8/9/02.
10.6	PHI	Employment Agreement of William J. Sim*	Exh. 10.10 to PHI's Form 10-Q, 8/9/02.
10.7	PHI	Pepco Holdings, Inc. Long-Term Incentive Plan*	Exh. 10.9 to PHI's Form 10-K, 3/13/06.

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10.8	PHI	Pepco Holdings, Inc. Executive and Director Deferred Compensation Plan*	Exh. 10.13 to PHI's Form 10-K, 10/13/06.
10.9	PHI Pepco	Potomac Electric Power Company Director and Executive Deferred Compensation Plan*	Exh. 10.22 to PHI's Form 10-K, 3/28/03.
10.10	PHI Pepco	Potomac Electric Power Company Long-Term Incentive Plan*	Exh. 4 to Pepco's Form S-8, 6/12/98.
10.11	PHI	Conectiv Incentive Compensation Plan*	Exh. 99(e) to Conectiv's Registration Statement No. 333-18843, 12/26/96.
10.12	PHI	Conectiv Supplemental Executive Retirement Plan*	Exh. 10.26 to PHI's Form 10-K, 3/28/03.
10.13	PHI 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.
10.14	PHI 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.
10.15	PHI 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.
10.16	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.
10.17	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.
10.18	PHI	Conectiv Deferred Compensation Plan*	Exh. 10.1 to PHI's Form 10-Q, 8/6/04.
10.19	PHI	Form of Employee Nonqualified Stock Option Agreement*	Exh. 10.2 to PHI's Form 10-Q, 11/8/04.

352

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10.20	PHI	Form of Director Nonqualified Stock Option Agreement*	Exh. 10.3 to PHI's Form 10-Q, 11/8/04.
10.21	PHI	Form of Election Regarding Payment of Director Retainer/Fees*	Exh. 10.4 to PHI's Form 10-Q, 11/8/04.
10.22	PHI	Form of Executive and Director Deferred Compensation Plan Executive Deferral Agreement*	Exh. 10.5 to PHI's Form 10-Q, 11/8/04.
10.23	PHI	Form of Executive Incentive Compensation Plan Participation Agreement*	Exh. 10.6 to PHI's Form 10-Q, 11/8/04.
10.24	PHI	Form of Restricted Stock Agreement*	Exh. 10.7 to PHI's Form 10-Q, 11/8/04.
10.25	PHI	Form of Election with Respect to Stock Tax Withholding*	Exh. 10.8 to PHI's Form 10-Q, 11/8/04.
10.26	PHI	Non-Management Directors Compensation Plan*	Exh. 10.2 to PHI's Form 8-K, 12/17/04.
10.27	PHI	Executive Annual Incentive Compensation Plan dated as of December 16, 2004*	Exh. 10.3 to PHI's Form 8-K, 12/17/04.
10.28	PHI	Non-Management Director Compensation Arrangements*	Exh. 10.56 to PHI's Form 10-K, 3/16/05.
10.29	PHI	Form of Election regarding Non-Management Directors Compensation Plan*	Exh. 10.57 to PHI's Form 10-K, 3/16/05.
10.30	PHI	PHI Named Executive Officer 2005 Compensation Determinations*	Exh. 10.58 to PHI's Form 10-K, 3/16/05.
10.31	PHI Pepco DPL ACE	Credit Agreement dated May 5, 2005 between PHI, Pepco, DPL and ACE and the Lenders named therein	Exh. 10.1 to PHI's Form 10-Q, 5/9/05.
10.32	PHI Pepco	Sale and Purchase Agreement, dated June 3, 2005, with John Akridge Development Company	Exh. 10.1 to PHI's Form 8-K, 7/22/05.
10.33	PHI Pepco	First Amendment to Sale and Purchase Agreement, dated June 8, 2005, with John Akridge Development Company	Exh. 10.2 to PHI's Form 8-K, 7/22/05.
10.34	PHI Pepco	Second Amendment to Sale and Purchase Agreement, dated July 18, 2005, with John Akridge Development Company	Exh. 10.3 to PHI's Form 8-K, 7/22/05.

353

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10.35	PHI ACE	Purchase and Sale Agreement, dated as of November 14, 2005, by and between Atlantic City Electric Company and Duquesne Light Holdings, Inc.	Exh. 2.1 to PHI's Form 8-K, 11/16/05.
10.36	PHI Pepco	Assignment of TPA Claim to Deutsche Bank Securities, Inc. dated December 19, 2005.	Exh. 10.48 to PHI's Form 10-K, 3/13/06.
10.37	PHI Pepco	Change-in-Control Severance Plan for Certain Executive Employees*	Exh. 10 to PHI's Form 8-K, 1/30/06.
10.38	PHI Pepco	PHI Named Executive Officer 2006 Compensation Determinations*	Exh. 10.50 to PHI's Form 10-K, 3/13/06.
10.39	PHI Pepco	Settlement Agreement and Release, dated as of May 30, 2006, by and among Potomac Electric Power Company and certain affiliated companies and Mirant Corporation and certain affiliated companies	Exh. 10.1 to PHI's Form 8-K, 5/31/06.
10.40	PHI	Short-Term Loan Agreement, dated as of August 10, 2006, between PHI and The Bank of Nova Scotia	Exh. 10.1 to PHI's Form 8-K, 8/10/06.
10.41	PHI	Note Purchase Agreement, dated December 12, 2006, among PHI and the purchasers named in Schedule A thereto	Exh. 1 to PHI's Form 8-K, 12/12/06.
10.42	PHI Pepco DPL ACE	First Amendment to Credit Agreement dated April 11, 2006, between PHI, Pepco, DPL and ACE and the Lenders named therein	Exh. 10 to PHI's Form 10-Q, 5/5/06.
10.43	PHI	Agreement and General Release of Claims between PHI and Eddie R. Mayberry*	Filed herewith.
10.44	PHI	Non-Competition, Non-Solicitation, and Confidentiality Agreement between PHI and Eddie R. Mayberry*	Filed herewith.
10.45	PHI	Agreement and General Release of Claims between PHI and William J. Sim*	Filed herewith.
10.46	PHI	Pepco Holdings, Inc. Combined Executive Retirement Plan*	Filed herewith.
10.47	PHI	PHI Named Executive Officer 2007 Compensation Determinations*	Filed herewith.
11	PHI	Statements Re: Computation of Earnings Per Common Share	**

354

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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	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.
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.

* Management contract or compensatory plan or arrangement.

**The information required by this Exhibit is set forth in Note (10) of the "Notes to Consolidated Financial Statements" of the Financial Statements of Pepco Holdings included in Item 8 "Financial Statements and Supplementary Data."

     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

355

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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

     Certain instruments defining the rights of the holders of long-term debt of PHI, Pepco, DPL and ACE (including medium-term notes, unsecured notes, senior notes and tax-exempt financing instruments) have not been filed as exhibits in accordance with Regulation S-K Item 601(b)(4)(iii) because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis. Each of PHI, Pepco, DPL or ACE agrees to furnish to the SEC upon request a copy of any such instruments omitted by it.

INDEX TO FURNISHED EXHIBITS
The documents listed below are being 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

(b)  Exhibits

356

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Exhibit 12.1  Statements Re. Computation of Ratios

PEPCO HOLDINGS, INC.

		For the Year Ended December 31,
		2006	2005	2004	2003	2002
		(Millions of dollars)
Income before extraordinary item (a)		$245.0	$368.5	$257.4	$204.9	$218.7
Income tax expense		161.4	255.2	167.3	62.1	124.9
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense		342.8	341.4	376.2	385.9	229.5
Other interest		18.8	20.3	20.6	21.7	21.0
Preferred dividend requirements     of subsidiaries		1.2	2.5	2.8	13.9	20.6
Total fixed charges		362.8	364.2	399.6	421.5	271.1
Nonutility capitalized interest		(1.0)	(.5)	(.1)	(10.2)	(9.9)
Income before extraordinary   item, income tax expense,   and fixed charges		$768.2	$987.4	$824.2	$678.3	$604.8
Total fixed charges, shown above		362.8	364.2	399.6	421.5	271.1
Increase preferred stock dividend   requirements of subsidiaries to   a pre-tax amount		.8	1.7	1.8	4.2	11.8
Fixed charges for ratio   computation		$363.6	$365.9	$401.4	$425.7	$282.9
Ratio of earnings to fixed charges   and preferred dividends		2.11	2.70	2.05	1.59	2.14
(a)	Excludes losses on equity investments.

357

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Exhibit 12.2  Statements Re. Computation of Ratios

POTOMAC ELECTRIC POWER COMPANY

		For the Year Ended December 31,
		2006	2005	2004	2003	2002
		(Millions of dollars)
Net income (a)		$ 85.4	$165.0	$ 96.5	$103.2	$141.1
Income tax expense		57.4	127.6	55.7	67.3	79.1
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense		77.1	82.8	82.5	83.8	114.5
Other interest		12.9	13.6	14.3	16.2	17.3
Preferred dividend requirements     of a subsidiary trust		-	-	-	4.6	9.2
Total fixed charges		90.0	96.4	96.8	104.6	141.0
Nonutility capitalized interest		-	-	-	-	(.2)
Income before income tax expense   and fixed charges		$232.8	$389.0	$249.0	$275.1	$361.0
Ratio of earnings to fixed charges		2.59	4.04	2.57	2.63	2.56
Total fixed charges, shown above		90.0	96.4	96.8	104.6	141.0
Preferred dividend requirements,   excluding mandatorily redeemable   preferred securities subsequent   to SFAS No. 150 implementation,   adjusted to a pre-tax amount		1.7	2.3	1.6	5.5	7.8
Total Fixed Charges and   Preferred Dividends		$ 91.7	$ 98.7	$ 98.4	$110.1	$148.8
Ratio of earnings to fixed charges   and preferred dividends		2.54	3.94	2.53	2.50	2.43
(a)	Excludes losses on equity investments.

358

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Exhibit 12.3  Statements Re. Computation of Ratios

DELMARVA POWER & LIGHT COMPANY

	For the Year Ended December 31,
	2006	2005	2004	2003	2002
	(Millions of dollars)
Net income	$ 42.5	$74.7	$ 63.0	$ 52.4	$ 51.5
Income tax expense	32.1	57.6	48.1	37.0	36.9
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense	41.3	35.3	33.0	37.2	44.1
Other interest	2.5	2.7	2.2	2.7	3.6
Preferred dividend requirements     of a subsidiary trust	-	-	-	2.8	5.7
Total fixed charges	43.8	38.0	35.2	42.7	53.4
Income before income tax expense   and fixed charges	$118.4	$170.3	$146.3	$132.1	$141.8
Ratio of earnings to fixed charges	2.70	4.48	4.16	3.09	2.66
Total fixed charges, shown above	43.8	38.0	35.2	42.7	53.4
Preferred dividend requirements,   adjusted to a pre-tax amount	1.4	1.8	1.7	1.7	2.9
Total fixed charges and   preferred dividends	$ 45.2	$ 39.8	$ 36.9	$ 44.4	$ 56.3
Ratio of earnings to fixed charges   and preferred dividends	2.62	4.28	3.96	2.98	2.52

359

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Exhibit 12.4  Statements Re. Computation of Ratios

ATLANTIC CITY ELECTRIC COMPANY

	For the Year Ended December 31,
	2006	2005	2004	2003	2002
	(Millions of dollars)
Income from continuing operations (a)	$ 60.1	$ 51.1	$ 58.8	$ 31.6	$ 17.1
Income tax expense	33.0	41.2	40.7	20.7	5.9
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense	64.9	60.1	62.2	63.7	55.6
Other interest	3.2	3.7	3.4	2.6	2.4
Preferred dividend requirements     of subsidiary trusts	-	-	-	1.8	7.6
Total fixed charges	68.1	63.8	65.6	68.1	65.6
Income before extraordinary   item, income tax expense and   fixed charges	$161.2	$156.1	$165.1	$120.4	$ 88.6
Ratio of earnings to fixed charges	2.37	2.45	2.52	1.77	1.35
Total fixed charges, shown above	68.1	63.8	65.6	68.1	65.6
Preferred dividend requirements   adjusted to a pre-tax amount	.5	.5	.5	.5	.9
Total fixed charges and   preferred dividends	$ 68.6	$ 64.3	$ 66.1	$ 68.6	$ 66.5
Ratio of earnings to fixed charges   and preferred dividends	2.35	2.43	2.50	1.76	1.33

(a) The ratios for 2005-2002 have been adjusted to reflect the discontinued operations of B.L. England, Keystone and Conemaugh as discussed in Note (13) to the financial statements of ACE included in Item 8, "Financial Statements and Supplementary Data."

360

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Exhibit 21    Subsidiaries of the Registrants

Name of Company	Jurisdiction of Incorporation or Organization
Pepco Holdings, Inc.	DE
Potomac Electric Power Company	D.C. & VA
Gridco International L.L.C.	DE
POM Holdings, Inc.	DE
Microcell Corporation	NC
Pepco Energy Services, Inc.	DE
Pepco Building Services, Inc.	DE
W.A. Chester, LLC	DE
W.A. Chester Corporation	DE
Chester Transmission Construction Canada, LLC	Canada
Severn Construction Services, LLC	DE
Chesapeake HVAC, Inc. (formerly Unitemp, Inc.)	DE
Conectiv Thermal Systems, Inc.	DE
ATS Operating Services, Inc.	DE
Atlantic Jersey Thermal Systems, Inc.	DE
Thermal Energy Limited Partnership I	DE
Eastern Landfill Gas, LLC	DE
Blue Ridge Renewable Energy, LLC	DE
Distributed Generation 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
Pepco Energy Cogeneration LLC	DE
Bethlehem Renewable Energy, LLC	DE
Potomac Capital Investment Corporation	DE
PCI Netherlands Corporation	NV
PCI Queensland Corporation	NV
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
Linpro Harmans Land LTD Partnership	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

361

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PCI Engine Trading, Ltd.	Bermuda
Potomac Capital Joint Leasing Corporation	DE
PCI Nevada Investments	DE
PCI Holdings, Inc.	DE
Aircraft International Management Company	DE
PCI-DB Ventures	DE
Potomac Nevada Investment, Inc.	NV
PCI Energy Corporation	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
Conectiv Properties and Investments, Inc.	DE
DCTC-Burney, Inc.	DE
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
Atlantic Generation, Inc.	NJ
Vineland Limited, Inc.	DE
Vineland Cogeneration L. P.	DE
Vineland General, Inc.	DE
Pedrick Gen., Inc.	NJ
Project Finance Fund III, L.P.	DE
Cogeneration Partners of America	NJ
Binghamton Limited, Inc.	DE
Binghamton General, Inc.	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

362

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Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-123525 and 333-129429) and the Registration Statements on Form S-8 (Nos. 333-96675, 333-121823 and 333-131371) of Pepco Holdings, Inc. of our report dated March 1, 2007 for Pepco Holdings, Inc. 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, D.C.
March 1, 2007

363

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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 1, 2007 relating to the financial statements and financial statement schedule of Potomac Electric Power Company, which appears in this Form 10-K.

PricewaterhouseCoopers LLP
Washington, D.C.
March 1, 2007

364

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Exhibit 23.3

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-115879 and 333-124331) of Delmarva Power & Light Company of our report dated March 1, 2007 relating to the financial statements and financial statement schedule of Delmarva Power & Light Company, which appears in this Form 10-K.

PricewaterhouseCoopers LLP
Washington, D.C.
March 1, 2007

365

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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 1, 2007 relating to the financial statements and financial statement schedule of Atlantic City Electric Company, which appears in this Form 10-K.

PricewaterhouseCoopers LLP
Washington, D.C.
March 1, 2007

366

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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 1, 2007			/S/ D. R. WRAASE                                    Dennis R. Wraase Chairman of the Board, President   and Chief Executive Officer

367

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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 1, 2007				/S/  JOSEPH M. RIGBY                         Joseph M. Rigby Senior Vice President and   Chief Financial Officer

368

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Exhibit 31.3
CERTIFICATION
I, Thomas S. Shaw, 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 1, 2007				/S/ T. S. SHAW                                   Thomas S. Shaw President and Chief Executive Officer

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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 1, 2007				/S/  JOSEPH M. RIGBY                       Joseph M. Rigby Senior Vice President and   Chief Financial Officer

370

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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 1, 2007				/S/  T. S. SHAW                                        Thomas S. Shaw President and Chief Executive Officer

371

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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 1, 2007				/S/  JOSEPH M. RIGBY                        Joseph M. Rigby Senior Vice President and   Chief Financial Officer

372

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Exhibit 31.7
CERTIFICATION
I, Thomas S. Shaw, 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 1, 2007				/S/  T. S. SHAW                                        Thomas S. Shaw President and Chief Executive Officer

373

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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 1, 2007				/S/  JOSEPH M. RIGBY               Joseph M. Rigby Chief Financial Officer

374

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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, 2006, 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 1, 2007	/S/  D. R. WRAASE                                  Dennis R. Wraase President and Chief Executive Officer
March 1, 2007	/S/  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.

375

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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, Thomas S. Shaw, 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, 2006, 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 1, 2007	/S/  T. S. SHAW                                        Thomas S. Shaw President and Chief Executive Officer
March 1, 2007	/S/   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.

376

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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, 2006, 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 1, 2007	/S/  T. S. SHAW                                    Thomas S. Shaw Chief Executive Officer
March 1, 2007	/S/  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.

377

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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, Thomas S. Shaw, 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, 2006, 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 1, 2007	/S/  T. S. SHAW                                        Thomas S. Shaw President and Chief Executive Officer
March 1, 2007	/S/  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.

378

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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 1, 2007	PEPCO HOLDINGS, INC.   (Registrant) By    /S/  D. R. WRAASE                                        Dennis R. Wraase         Chairman of the Board,           President and Chief           Executive Officer
March 1, 2007	POTOMAC ELECTRIC POWER COMPANY (Pepco)   (Registrant) By     /S/  T. S. SHAW                                       Thomas S. Shaw,         President and Chief           Executive Officer
March 1, 2007	DELMARVA POWER & LIGHT COMPANY (DPL)     (Registrant) By     /S/  T. S. SHAW                                       Thomas S. Shaw,         President and Chief           Executive Officer
March 1, 2007	ATLANTIC CITY ELECTRIC COMPANY (ACE)   (Registrant) By     /S/  T. S. SHAW                                       Thomas S. Shaw,         President and Chief           Executive Officer

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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:

/S/  D. R. WRAASE                Dennis R. Wraase	Chairman of the Board, President and Chief Executive Officer of Pepco Holdings, Chairman of the Board of Pepco and Director of Pepco Holdings, Pepco, DPL and ACE (Principal Executive Officer of Pepco Holdings)	March 1, 2007
/S/  T. S. SHAW                    Thomas S. Shaw	Director, President and Chief Executive Officer of Pepco, DPL and ACE (Principal Executive Officer of Pepco, DPL and ACE)	March 1, 2007
/S/  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 1, 2007
/S/  RONALD K. CLARK      Ronald K. Clark	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 1, 2007

380

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Signature	Title	Date
/s/ EDMUND B. CRONIN, JR.        Edmund B. Cronin, Jr.	Director, Pepco Holdings	March 1, 2007
/s/ J. B. DUNN                                  Jack B. Dunn, IV	Director, Pepco Holdings	March 1, 2007
/s/ T. C. GOLDEN                            Terence C. Golden	Director, Pepco Holdings	March 1, 2007
/s/ FRANK O. HEINTZ                    Frank O. Heintz	Director, Pepco Holdings	March 1, 2007
/s/ GEORGE F. MacCORMACK    George F. MacCormack	Director, Pepco Holdings	March 1, 2007
/s/ RICHARD B. McGLYNN           Richard B. McGlynn	Director, Pepco Holdings	March 1, 2007
/s/ LAWRENCE C. NUSSDORF     Lawrence C. Nussdorf	Director, Pepco Holdings	March 1, 2007
/s/ PETER F. O'MALLEY                Peter F. O'Malley	Director, Pepco Holdings	March 1, 2007
/s/ FRANK ROSS                             Frank K. Ross	Director, Pepco Holdings	March 1, 2007
Pauline A. Schneider	Director, Pepco Holdings
/s/ LESTER P. SILVERMAN           Lester P. Silverman	Director, Pepco Holdings	March 1, 2007
/s/ WILLIAM T. TORGERSON      William T. Torgerson	Director of Pepco Holdings, Pepco, DPL and ACE	March 1, 2007

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INDEX TO EXHIBITS FILED HEREWITH
Exhibit No.	Registrant(s)	Description of Exhibit
3.3	DPL	Articles of Restatement of Certificate and Articles of Incorporation (filed in Delaware and Virginia 02/22/07)
10.43	PHI	Agreement and General Release of Claims between PHI and Eddie R. Mayberry
10.44	PHI	Non-Competition, Non-Solicitation, and Confidentiality Agreement between PHI and Eddie R. Mayberry
10.45	PHI	Agreement and General Release of Claims between PHI and William J. Sim
10.46	PHI	Pepco Holdings, Inc. Combined Executive Retirement Plan
10.47	PHI	PHI Named Executive Officer 2007 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	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

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

382

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