UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

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

THE SECURITIES EXCHANGE ACT OF 1934

For the quarter ended March 31, 2008

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer.  See definition of “accelerated filer and large 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 Exchange Act).

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

Pepco, DPL, and ACE meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with reduced disclosure format specified in General Instruction H(2) of Form 10-Q.

Registrant	Number of Shares of Common Stock of the Registrant Outstanding at March 31, 2008
Pepco Holdings	201,396,295 ($.01 par value)
Pepco	100 ($.01 par value) (a)
DPL	1,000 ($2.25 par value) (b)
ACE	8,546,017 ($3 par value) (b)

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

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

TABLE OF CONTENTS
			Page
	Glossary of Terms		i
PART I	FINANCIAL INFORMATION		1
Item 1.	-	Financial Statements	1
Item 2.	-	Management’s Discussion and Analysis of    Financial Condition and Results of Operations	98
Item 3.	-	Quantitative and Qualitative Disclosures    About Market Risk	151
Item 4.	-	Controls and Procedures	154
Item 4T.	-	Controls and Procedures	155
PART II	OTHER INFORMATION		156
Item 1.	-	Legal Proceedings	156
Item 1A.	-	Risk Factors	157
Item 2.	-	Unregistered Sales of Equity Securities and Use of Proceeds	157
Item 3.	-	Defaults Upon Senior Securities	157
Item 4.	-	Submission of Matters to a Vote of Security Holders	158
Item 5.	-	Other Information	158
Item 6.	-	Exhibits	159
Signatures			176

TABLE OF CONTENTS - EXHIBITS
Exh. No.	Registrant(s)	Description of Exhibit	Page
12.1	PHI	Statements Re: Computation of Ratios	160
12.2	Pepco	Statements Re: Computation of Ratios	161
12.3	DPL	Statements Re: Computation of Ratios	162
12.4	ACE	Statements Re: Computation of Ratios	163
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	164
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	165
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	166
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	167
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	168
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	169
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	170
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	171
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	172
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	173
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	174
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	175

GLOSSARY OF TERMS

Term	Definition
2007 Maryland Rate Order	The MPSC’s approval of new electric service distribution base rates for Pepco and DPL in Maryland, effective June 16, 2007
A&N	A&N Electric Cooperative, purchaser of DPL’s retail electric distribution business in Virginia
ABO	Accumulated benefit obligation
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
ADFIT	Accumulated deferred federal income taxes
ADITC	Accumulated deferred investment tax credits
Ancillary services	Generally, electricity generation reserves and reliability services
AOCI	Accumulated Other Comprehensive Income
APIC	Additional paid-in capital
ARB	Accounting Research Bulletin
Appellate Division	Appellate Division of the Superior Court of New Jersey
BGS	Basic Generation Service (the supply of electricity by ACE to retail customers in New Jersey who have not elected to purchase electricity from a competitive supplier)
BSA	Bill Stabilization Adjustment
Citgo	Citgo Asphalt Refining Company
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
DCPSC	District of Columbia Public Service Commission
Default Electricity   Supply	The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as SOS or BGS service
Default Supply Revenue	Revenue received for Default Electricity Supply
Delaware District Court	United States District Court for the District of Delaware
DPL	Delmarva Power & Light Company
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

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Term	Definition
FIN	FASB Interpretation Number
FSP	FASB Staff Position
GAAP	Accounting principles generally accepted in the United States of America
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.
IRC	Internal Revenue Code
IRS	Internal Revenue Service
ISONE	Independent System Operator - New England
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
LIBOR	London Inter-Bank Offered Rate
LTIP	Pepco Holdings’ Long-Term Incentive Plan
MAPP Project	Mid-Atlantic Power Pathway Project
Mirant	Mirant Corporation
MPSC	Maryland Public Service Commission
NFA	No Further Action letter issued by the NJDEP
NGC	Non Utility Generation Charge in New Jersey
NJBPU	New Jersey Board of Public Utilities
NJDEP	New Jersey Department of Environmental Protection
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
NUGs	Non-utility generators
NYDEC	New York Department of Environmental Conservation
OAL	New Jersey Office of Administrative Law
OCI	Other Comprehensive Income
ODEC	Old Dominion Electric Cooperative, purchaser of DPL’s wholesale transmission business in Virginia
Panda	Panda-Brandywine, L.P.
Panda PPA	PPA between Pepco and Panda
PBO	Projected benefit obligation
PCI	Potomac Capital Investment Corporation and its subsidiaries
Pepco	Potomac Electric Power Company
Pepco Energy Services	Pepco Energy Services, Inc. and its subsidiaries
Pepco Holdings or PHI	Pepco Holdings, Inc.
PHI 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
PJM RTO	PJM Regional Transmission Organization

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Term	Definition
Power Delivery	PHI’s Power Delivery Business
PPA	Power Purchase Agreement
PRP	Potentially responsible party
PUHCA 2005	Public Utility Holding Company Act of 2005, which became effective February 8, 2006
RAR	IRS revenue agent’s report
RC Cape May	RC Cape May Holdings, LLC, an affiliate of Rockland Capital Energy Investments, LLC, and the purchaser of the B.L. England generating facility
Regulated T&D Electric   Revenue	Revenue from the transmission and the delivery of electricity to PHI’s customers within its service territories at regulated rates
Revenue Decoupling   Adjustment	Amount by which revenue from Maryland distribution sales either exceeds or falls short of the MDPSC-approved revenue based on the distribution charge per customer in the 2007 Maryland Rate Order
ROE	Return on equity
SBC	Societal Benefits Charge in New Jersey
SEC	Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SOS	Standard Offer Service (the supply of electricity by Pepco in the District of Columbia, by Pepco and DPL in Maryland and by DPL in Delaware, to retail customers who have not elected to purchase electricity from a competitive supplier)
Spot	Commodities market in which goods are sold for cash and delivered immediately
Standard Offer Service   revenue or SOS revenue	Revenue Pepco and DPL, respectively, receive for the procurement of energy for its SOS customers
Starpower	Starpower Communications, LLC
Stipulation	Stipulation of Settlement executed by ACE, NJBPU staff and the New Jersey Division of Rate Counsel in the New Jersey distribution rate case
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.
Tolling agreement	A physical or financial contract where one party delivers fuel to a specific generating station in exchange for the power output
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
TSA	Contract for terminal services between ACE and Citgo
VaR	Value at Risk

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PART I    FINANCIAL INFORMATION

Item 1.   FINANCIAL STATEMENTS

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

	Registrants
Item	Pepco Holdings	Pepco*	DPL*	ACE
Consolidated Statements of Earnings	3	41	61	79
Consolidated Statements of Comprehensive Earnings	4	N/A	N/A	N/A
Consolidated Balance Sheets	5	42	62	80
Consolidated Statements of Cash Flows	7	44	64	82
Notes to Consolidated Financial Statements	8	45	65	83

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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EARNINGS (Unaudited)
	Three Months Ended March 31,
	2008			2007
(In millions, except per share data)
Operating Revenue
Power Delivery	$	1,295.5		$	1,275.1
Competitive Energy		1,328.2			887.1
Other		17.2			16.6
Total Operating Revenue		2,640.9			2,178.8
Operating Expenses
Fuel and purchased energy		1,817.5			1,477.0
Other services cost of sales		180.3			138.1
Other operation and maintenance		219.5			207.1
Depreciation and amortization		90.9			93.1
Other taxes		88.2			85.3
Deferred electric service costs		24.7			28.1
Gain on sale of assets		(3.1	)		(2.5	)
Total Operating Expenses		2,418.0			2,026.2
Operating Income		222.9			152.6
Other Income (Expenses)
Interest and dividend income		7.1			3.3
Interest expense		(81.0	)		(84.6	)
(Loss) Income from equity investments		(2.1	)		3.4
Other income		5.6			8.6
Other expenses		(.6	)		(.2	)
Total Other Expenses		(71.0	)		(69.5	)
Preferred Stock Dividend Requirements of Subsidiaries		.1			.1
Income Before Income Tax Expense		151.8			83.0
Income Tax Expense		52.6			31.4
Net Income		99.2			51.6
Retained Earnings at Beginning of Period		1,192.7			1,068.7
Cumulative Effect Adjustment Related to the    Implementation of FIN 48		-			(7.4	)
LTIP Dividend		(.1	)		(.2	)
Dividends Paid on Common Stock (Note 12)		(54.2	)		(50.1	)
Retained Earnings at End of Period	$	1,237.6		$	1,062.6
Basic and Diluted Share Information
Weighted average shares outstanding		201.0			192.5
Earnings per share of common stock	$	.49		$	.27

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

(Unaudited)

	Three Months Ended March 31,
	2008		2007
	(Millions of dollars)
Net income	$	99.2	$	51.6
Other comprehensive earnings
Unrealized gains (losses) on commodity     derivatives designated as cash flow hedges:
Unrealized holding gains arising during period		208.6		18.7
Less:  reclassification adjustment for                  gains (losses) included in net earnings		11.8		(11.8	)
Net unrealized gains on commodity derivatives		196.8		30.5
Realized gain on Treasury Lock transaction		1.4		2.9
Amortization of gains and losses for prior service costs		.3		-
Other comprehensive earnings, before taxes		198.5		33.4
Income tax expense		78.9		11.8
Other comprehensive earnings, net of income taxes		119.6		21.6
Comprehensive earnings	$	218.8	$	73.2

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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
ASSETS		March 31, 2008		December 31, 2007
	(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$	316.2	$	55.1
Restricted cash			28.0		14.5
Accounts receivable, less allowance for uncollectible      accounts of $31.2 million and $30.6 million, respectively			1,241.4		1,278.3
Fuel, materials and supplies-at average cost			266.2		287.9
Unrealized gains - derivative contracts			215.0		43.0
Prepayments of income taxes			187.9		249.8
Prepaid expenses and other			87.4		68.5
Total Current Assets			2,342.1		1,997.1
INVESTMENTS AND OTHER ASSETS
Goodwill			1,409.6		1,409.6
Regulatory assets			1,490.9		1,515.7
Investment in finance leases held in trust			1,402.9		1,384.4
Income taxes receivable			197.9		196.1
Restricted cash and cash equivalents			420.9		424.1
Other			404.1		307.3
Total Investments and Other Assets			5,326.3		5,237.2
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			12,373.4		12,306.5
Accumulated depreciation			(4,448.9)		(4,429.8)
Net Property, Plant and Equipment			7,924.5		7,876.7
TOTAL ASSETS		$	15,592.9	$	15,111.0

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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY	March 31, 2008		December 31, 2007
(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$	186.7	$	288.8
Current maturities of long-term debt and project funding		289.0		332.2
Accounts payable and accrued liabilities		811.2		796.7
Capital lease obligations due within one year		6.0		6.0
Taxes accrued		116.4		133.5
Interest accrued		80.0		70.1
Liabilities and accrued interest related to uncertain tax positions		150.8		131.7
Other		309.3		277.8
Total Current Liabilities		1,949.4		2,036.8
DEFERRED CREDITS
Regulatory liabilities		1,275.6		1,248.9
Deferred income taxes, net		2,247.1		2,105.1
Investment tax credits		37.8		38.9
Pension benefit obligation		67.9		65.5
Other postretirement benefit obligations		388.9		385.5
Income taxes payable		166.2		164.9
Other		271.7		306.2
Total Deferred Credits		4,455.2		4,315.0
LONG-TERM LIABILITIES
Long-term debt		4,435.6		4,174.8
Transition Bonds issued by ACE Funding		425.7		433.5
Long-term project funding		20.4		20.9
Capital lease obligations		105.3		105.4
Total Long-Term Liabilities		4,987.0		4,734.6
COMMITMENTS AND CONTINGENCIES (NOTE 12)
MINORITY INTEREST		6.2		6.2
SHAREHOLDERS’ EQUITY
Common stock, $.01 par value, authorized 400,000,000 shares,     201,396,295 shares and 200,512,890 shares outstanding, respectively		2.0		2.0
Premium on stock and other capital contributions		2,881.4		2,869.2
Accumulated other comprehensive earnings (loss)		74.1		(45.5	)
Retained earnings		1,237.6		1,192.7
Total Shareholders’ Equity		4,195.1		4,018.4
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	15,592.9	$	15,111.0

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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
	Three Months Ended March 31,
	2008			2007
(Millions of dollars)
OPERATING ACTIVITIES
Net income	$	99.2		$	51.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		90.9			93.1
Gain on sale of assets		(3.1	)		(2.5	)
Rents received from leveraged leases under income earned		(18.6	)		(19.1	)
Deferred income taxes		65.3			28.0
Changes in:
Accounts receivable		(24.4	)		24.1
Regulatory assets and liabilities		32.6			17.6
Materials and supplies		21.4			31.8
Accounts payable and accrued liabilities		2.7			.1
Interest and taxes accrued		(3.9	)		(21.8	)
Cash collateral related to derivative activities		117.7			59.4
Other changes in working capital		6.0			(5.9	)
Net other operating		(38.8	)		1.1
Net Cash From Operating Activities		347.0			257.5
INVESTING ACTIVITIES
Net investment in property, plant and equipment		(170.9	)		(127.0	)
Proceeds from sale of assets		50.6			10.6
Changes in restricted cash		(13.5	)		(5.1	)
Net other investing activities		1.5			1.5
Net Cash Used By Investing Activities		(132.3	)		(120.0	)
FINANCING ACTIVITIES
Dividends paid on common stock		(54.2	)		(50.1	)
Dividends paid on preferred stock		(.1	)		(.1	)
Common stock issued for the Dividend Reinvestment Plan		7.2			7.0
Issuance of common stock		12.5			19.9
Redemption of preferred stock of subsidiaries		-			(18.2	)
Issuances of long-term debt		400.1			.3
Reacquisition of long-term debt		(183.3	)		(88.1	)
(Repayments) issuances of short-term debt, net		(102.1	)		32.5
Net other financing activities		(33.7	)		(7.8	)
Net Cash From (Used By) Financing Activities		46.4			(104.6	)
Net Increase in Cash and Cash Equivalents		261.1			32.9
Cash and Cash Equivalents at Beginning of Period		55.1			48.8
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	316.2		$	81.7
NONCASH ACTIVITIES
Asset retirement obligations associated with removal costs   transferred (from) to regulatory liabilities	$	(2.6	)	$	4.0
Recoverable pension/OPEB costs included in regulatory assets	$	(4.0	)	$	-
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash (received) paid for income taxes	$	(2.1	)	$	.6

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), a Delaware corporation incorporated in 2001, 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), conducted through the following regulated public utility companies, each of which is a reporting company under the Securities Exchange Act of 1934, as amended:

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

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

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

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

PHI Service Company, a subsidiary service company of PHI, provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services to PHI and its operating subsidiaries.  These services are provided pursuant to a service agreement among PHI, PHI Service Company, and the participating operating subsidiaries.  The expenses of the 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, distribution and default supply of electricity and the delivery and supply of natural gas.

Each of Pepco, DPL and ACE is a regulated public utility in the jurisdictions that comprise its service territory.  Each company owns and operates a network of wires, substations and other equipment that is classified either as transmission or distribution facilities.  Transmission facilities are high-voltage systems that carry wholesale electricity into, or across,

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the utility’s service territory.  Distribution facilities are low-voltage systems that carry electricity to end-use customers in the utility’s service territory.  Together the three companies constitute a single segment for financial reporting purposes.

Each company is responsible for the delivery of electricity and, in the case of DPL, natural gas in its service territory, for which it is paid tariff rates established by the 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	Standard Offer Service (SOS)
District of Columbia	SOS
Maryland	SOS
New Jersey	Basic Generation Service (BGS)
Virginia	Default Service (prior to January 2, 2008)

In this Form 10-Q, these supply services 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 Conectiv Energy and Pepco Energy Services.  Conectiv Energy and Pepco Energy Services are separate operating segments for financial reporting purposes.

Other Business Operations

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy sale-leaseback transactions, with a book value at March 31, 2008 of approximately $1.4 billion.  This activity constitutes a fourth operating segment, which is designated as “Other Non-Regulated” for financial reporting purposes.  For a discussion of PHI’s cross-border leasing transactions, see “Regulatory and Other Matters -- Federal Tax Treatment of Cross-Border Leases,” in Note (12), “Commitments and Contingencies.”

(2)  SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

Pepco Holdings’ unaudited consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP).  Pursuant to the rules and regulations of the Securities and Exchange Commission (SEC), certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted.  Therefore, these financial statements should be read along with the annual financial statements included in PHI’s Annual Report on Form 10-K for the year ended December 31, 2007.  In the opinion of PHI’s management, the consolidated

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financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly Pepco Holdings’ financial condition as of March 31, 2008, in accordance with GAAP.  The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.  Interim results for the three months ended March 31, 2008 may not be indicative of PHI’s results that will be realized for the full year ending December 31, 2008, since its Power Delivery and Competitive Energy businesses are seasonal.

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 Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R (revised December 2003), entitled “Consolidation of Variable Interest Entities” (FIN 46R) and FASB Staff Position (FSP) 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)” (FSP FIN 46(R)-6), Pepco Holdings continued, during the first quarter of 2008, 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 variable interest entities or if Pepco Holdings’ subsidiaries were the primary beneficiaries. 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 three months ended March 31, 2008 and 2007 were approximately $108 million and $105 million, respectively, of which approximately $96 million for each period related to power purchases under the NUGs and the Panda PPA.  Pepco Holdings does not have loss exposure under the NUGs because cost recovery will be achieved from ACE’s customers through regulated rates.  There is no loss exposure under the Panda PPA as recovery will be achieved through the sale of purchased power into PJM Interconnection, LLC (PJM), with the funds received from the Mirant Corporation (Mirant) bankruptcy settlement covering the amount by which the purchase cost exceeds the proceeds from the sale.

Taxes Assessed by a Governmental Authority on Revenue-producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $74.2 million and $73.3 million for the three months ended March 31, 2008 and 2007, respectively.

Reclassifications

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

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(3)  NEWLY ADOPTED ACCOUNTING STANDARDS

SFAS No. 157, "Fair Value Measurements"

In September 2006, the FASB issued Statement of Financial Accounting Standards 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.

SFAS No. 157 nullified a portion of Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,”(EITF 02-3).  Under EITF 02-3, the transaction price presumption prohibited recognition of a trading profit at inception of a derivative unless the positive fair value of that derivative was substantially based on quoted prices or a valuation process incorporating observable inputs.  For transactions that did not meet this criterion at inception, trading profits that had been deferred were recognized in the period that inputs to value the derivative became observable or when the contract performed.  SFAS No. 157 nullified this portion of EITF 02-3.  SFAS No. 157 also: (1) establishes that fair value is based on a hierarchy of inputs into the valuation process (as described in Note 11), (2) clarifies that an issuer's credit standing should be considered when measuring liabilities at fair value, (3) precludes the use of a liquidity or blockage factor discount when measuring instruments traded in an actively quoted market at fair value and (4) requires costs relating to acquiring instruments carried at fair value to be recognized as expense when incurred.  SFAS No. 157 requires that a fair value measurement reflect the assumptions market participants would use in pricing an asset or liability based on the best available information.  These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model.

The provisions of SFAS No. 157 are to be applied prospectively, except for the initial impact on three specific items: (1) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF 02-3, (2) existing hybrid financial instruments measured initially at fair value using the transaction price and (3) blockage factor discounts.  Adjustments to these items required under SFAS No. 157 are to be recorded as a transition adjustment to beginning retained earnings in the year of adoption.

The provisions of SFAS No. 157, as issued, are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (January 1, 2008 for Pepco Holdings).  On February 12, 2008, the FASB issued FSP No. 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” (FSP No. 157-1) that removes certain leasing transactions from the scope of SFAS No. 157.  On February 12, 2008, the FASB also issued FSP No. 157-2, “Effective Date of FASB Statement No. 157” (FSP No. 157-2) which defers the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually).  FSP No. 157-2 defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of the Final Staff Positions.

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Pepco Holdings applied the guidance of FSP No. 157-1 and FSP No. 157-2 with its adoption of SFAS No. 157 on January 1, 2008.  The adoption of SFAS No. 157 did not result in a transition adjustment to beginning retained earnings and did not have a material impact on PHI’s overall financial condition, results of operations or cash flows.  SFAS No. 157 also requires new disclosures regarding the level of pricing observability associated with financial instruments carried at fair value.  This additional disclosure is provided in Note 11, “Fair Value Disclosures,” herein.  Additionally, with the deferral of the effective date of SFAS No. 157 for certain non-financial assets and non-financial liabilities under FSP No. 157-2, PHI does not anticipate any material changes to 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 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 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 the beginning of a reporting entity’s first fiscal year that begins after November 15, 2007 (January 1, 2008 for Pepco Holdings).  Pepco Holdings adopted the provisions of SFAS No. 159 on January 1, 2008 and chose not to elect the fair value option for its eligible financial assets and liabilities.

FSP FIN 39-1, “Amendment of FASB Interpretation No. 39”

On April 30, 2007, the FASB issued FSP FIN 39-1, “Amendment of FASB Interpretation No. 39,” to amend certain portions of Interpretation 39.  The FSP replaces the terms “conditional contracts” and “exchange contracts” in Interpretation 39 with the term “derivative instruments” as defined in SFAS Statement No. 133 “Accounting for Derivative Instrument and Hedging Activities” (SFAS No. 133).  The FSP also amends Interpretation 39 to allow for the offsetting of fair value amounts for the right to reclaim cash collateral or receivable, or the obligation to return cash collateral or payable, arising from the same master

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netting arrangement as the derivative instruments. FSP FIN 39-1 applies to fiscal years beginning after November 15, 2007 (January 1, 2008 for Pepco Holdings).

Pepco Holdings retrospectively adopted the provisions of FSP FIN 39-1 and elected to offset fair value amounts recognized for derivative instruments and fair value amounts recognized for related collateral positions executed with the same counterparty under a master netting arrangement.  Additional disclosure of collateral positions that have been offset against net derivative positions is provided in Note 13.  The effect of retrospective application of FSP FIN 39-1 was not material at December 31, 2007 and, as such, no amounts were reclassified.

EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards”

On June 27, 2007, the FASB ratified EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards” (EITF 06-11) which provides that a realized income tax benefit from dividends or dividend equivalents that are charged to retained earnings and paid to employees for equity classified nonvested equity shares, nonvested equity share units, and outstanding equity share options should be recognized as an increase to additional paid-in capital (APIC).  The amount recognized in APIC for the realized income tax benefit from dividends on those awards should be included in the pool of excess tax benefits available to absorb tax deficiencies on share-based payment awards (i.e. the “APIC pool”).

EITF Issue No. 06-11 also provides that, when the estimated amount of forfeitures increases or actual forfeitures exceed estimates, the amount of tax benefits previously recognized in APIC should be reclassified into the income statement; however, the amount reclassified is limited to the APIC pool balance on the reclassification date.

EITF Issue No. 06-11 applies prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years beginning after December 15, 2007, and interim periods within those fiscal years (January 1, 2008 for Pepco Holdings).  Early application is permitted as of the beginning of a fiscal year for which interim or annual financial statements have not yet been issued.  Retrospective application to previously issued financial statements is prohibited.  Entities must disclose the nature of any change in their accounting policy for income tax benefits of dividends on share-based payment awards resulting from the adoption of this guidance.  Pepco Holdings adopted the provisions of EITF 06-11 on January 1, 2008.  The adoption of EITF 06-11 did not have a material impact on PHI’s overall financial condition, results of operations or cash flows.

(4)  RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

SFAS No. 141(R), “Business Combinations – a replacement of FASB Statement No. 141”

On December 4, 2007, the FASB issued SFAS No. 141(R), “Business Combinations – a replacement of FASB Statement No. 141” (SFAS No. 141(R)) which replaces FASB Statement No. 141, “Business Combinations.”  This Statement retains the fundamental requirements in Statement 141 that the acquisition method of accounting (which Statement 141 called the

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purchase method) be used for all business combinations and for an acquirer to be identified for each business combination.

SFAS No. 141(R) applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree).  It does not apply to (i) the formation of a joint venture, (ii) the acquisition of an asset or a group of assets that does not constitute a business, (iii) a combination between entities or businesses under common control and (iv) a combination between not-for-profit organizations or the acquisition of a for-profit business by a not-for-profit organization.

This Statement amends FASB Statement No. 109, Accounting for Income Taxes, to require the acquirer to recognize changes in the amount of its deferred tax benefits that are recognizable because of a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances (such changes arise through the increase or reduction of the acquirer’s valuation allowance on its previously existing deferred tax assets because of the business combination).  Previously, Statement 109 required a reduction of the acquirer’s valuation allowance because of a business combination to be recognized through a corresponding reduction to goodwill.

SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for Pepco Holdings).  An entity may not apply it before that date.  Pepco Holdings is currently evaluating the impact SFAS No. 141(R) may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51”

On December 4, 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51” (SFAS No. 160), which amends ARB 51 to establish accounting and reporting standards for a noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary.  It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.

A noncontrolling interest, sometimes called a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. The objective of SFAS No. 160 is to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards that require (i) the ownership interests in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated statement of financial position within equity, but separate from the parent’s equity, (ii) the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of income, (iii) the changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently, and (iv) when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary must be initially measured at fair value.  The gain or loss on the deconsolidation of the subsidiary is measured using the fair

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value of any noncontrolling equity investment rather than the carrying amount of that retained investment and SFAS No. 160 requires that entities provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.

SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for Pepco Holdings).  Earlier adoption is prohibited.  SFAS No. 160 shall be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, except for the presentation and disclosure requirements.  The presentation and disclosure requirements shall be applied retrospectively for all periods presented.  Pepco Holdings is currently evaluating the impact SFAS No. 160 may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133”

On March 19, 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (SFAS No. 161) which changes the disclosure requirements for derivative instruments and hedging activities.  Entities will be required to provide enhanced disclosures about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows.

The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This disclosure is designed to better convey the purpose of derivative use in terms of the risks that the entity is intending to manage. Disclosing the fair values of derivative instruments and their gains and losses in a tabular format is intended to provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features should provide information on the potential effect on an entity’s liquidity from using derivatives.

SFAS No. 161 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after November 15, 2008 (January 1, 2009 for Pepco Holdings).  Earlier adoption is encouraged.  SFAS No. 161 encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption.  Pepco Holdings is currently evaluating the impact SFAS No. 161 may have on its footnote disclosure requirements.

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(5)  SEGMENT INFORMATION

Based on the provisions of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” Pepco Holdings’ management has identified its operating segments at March 31, 2008 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated.  Intrasegment revenues and expenses are eliminated at the segment level for purposes of presenting segment financial results.  Segment financial information for the three months ended March 31, 2008 and 2007, is as follows.

	Three Months Ended March 31, 2008                                          (Millions of dollars)
				Competitive Energy Segments
	Power Delivery			Conectiv Energy			Pepco Energy Services		Other    Non-    Regulated		Corp.  & Other (a)		PHI      Cons.
Operating Revenue	$	1,295.5		$	822.7	(b)	$	620.7	$	18.6	$	(116.6)	$	2,640.9
Operating Expense (c)		1,190.7	(b)		736.0			607.3		1.2		(117.2)		2,418.0
Operating Income		104.8			86.7			13.4		17.4		.6		222.9
Interest Income		5.9			.7			.4		1.0		(.9)		7.1
Interest Expense		48.4			6.3			.4		4.4		21.5		81.0
Other Income		4.3			.1			.5		(2.4)		.4		2.9
Preferred Stock    Dividends		.1			-			-		.7		(.7)		.1
Income Taxes		19.1			32.8			5.3		1.3		(5.9)		52.6
Net Income (loss)		47.4			48.4			8.6		9.6		(14.8)		99.2
Total Assets		9,885.1			1,982.4			697.8		1,442.8		1,584.8		15,592.9
Construction    Expenditures	$	147.5		$	15.5		$	4.7	$	-	$	3.2	$	170.9

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 $(116.6) million for Operating Revenue, $(115.1) million for Operating Expense, $(16.1) million for Interest Income, $(15.4) million for Interest Expense, and $(.7) million for Preferred Stock Dividends.
(b)	Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $97.8 million for the three months ended March 31, 2008.
(c)	Includes depreciation and amortization of $90.9 million, consisting of $76.6 million for Power Delivery, $9.2 million for Conectiv Energy, $2.8 million for Pepco Energy Services, $.5 million for Other Non-Regulated, and $1.8 million for Corp. & Other.

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	Three Months  Ended March 31, 2007                                          (Millions of dollars)
				Competitive Energy Segments
	Power Delivery			Conectiv Energy			Pepco Energy Services		Other    Non-    Regulated		Corp.  & Other (a)		PHI      Cons.
Operating Revenue	$	1,275.1		$	496.1	(b)	$	509.9	$	19.3	$	(121.6)	$	2,178.8
Operating Expense (c)		1,180.9	(b)		456.9			508.8		1.0		(121.4)		2,026.2
Operating Income		94.2			39.2			1.1		18.3		(.2)		152.6
Interest Income		1.8			1.2			.9		2.7		(3.3)		3.3
Interest Expense		45.5			8.4			1.3		9.2		20.2		84.6
Other Income		4.8			.1			3.3		3.3		.3		11.8
Preferred Stock    Dividends		.1			-			-		.6		(.6)		.1
Income Taxes		22.0			13.1			1.4		3.7		(8.8)		31.4
Net Income (loss)		33.2			19.0			2.6		10.8		(14.0)		51.6
Total Assets		9,097.3			1,723.6			563.8		1,585.7		1,351.1		14,321.5
Construction    Expenditures	$	118.3		$	5.9		$	1.7	$	-	$	1.1	$	127.0

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 $(121.7) million for Operating Revenue, $(120.4) million for Operating Expense, $(20.9) million for Interest Income, $(20.3) million for Interest Expense, and $(.6) million for Preferred Stock Dividends.
(b)	Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $111.1 million for the three months ended March 31, 2007.
(c)	Includes depreciation and amortization of $93.1 million, consisting of $78.1 million for Power Delivery, $9.3 million for Conectiv Energy, $2.9 million for Pepco Energy Services, $.5 million for Other Non-Regulated, and $2.3 million for Corp. & Other.

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(6)  PENSIONS AND OTHER POSTRETIREMENT BENEFITS

The following Pepco Holdings information is for the three months ended March 31, 2008 and 2007.

		Pension Benefits				Other Postretirement Benefits
		2008		2007		2008		2007
	(Millions of dollars)
Service cost	$	9.9	$	10.7	$	2.0	$	2.7
Interest cost		25.4		24.6		9.2		9.9
Expected return on plan assets		(33.0)		(33.2)		(2.4)		(4.0)
Prior service cost/(credit) component		.1		.2		(1.0)		(.9)
(Gain)/loss component		3.1		3.7		2.7		3.3
Net periodic benefit cost	$	5.5	$	6.0	$	10.5	$	11.0

Pension

The pension net periodic benefit cost for the three months ended March 31, 2008, of $5.5 million includes $2.6 million for Pepco, $.8 million for ACE, and $(1.3) million for DPL.  The pension net periodic benefit cost for the three months ended March 31, 2007, of $6.0 million includes $3.2 million for Pepco, $1.0 million for ACE, and $(1.5) million for DPL.  The remaining pension net periodic benefit cost is for other PHI subsidiaries.

Pension Contributions

Pepco Holdings’ current funding policy with regard to its defined benefit pension plan is to maintain a funding level in excess of 100% of its accumulated benefit obligation (ABO).  PHI’s pension plan currently meets the minimum funding requirements of the Employment Retirement Income Security Act of 1974 (ERISA) without any additional funding.  PHI may elect, however, to make a discretionary tax-deductible contribution to maintain the pension plan’s assets in excess of its ABO.  During the quarters ended March 31, 2008 and 2007, no contributions were made.  The potential discretionary funding of the pension plan in 2008 will depend on many factors, including the actual investment return earned on plan assets over the remainder of the year.

Other Postretirement Benefits

The other postretirement net periodic benefit cost for the three months ended March 31, 2008, of $10.5 million includes $3.7 million for Pepco, $2.5 million for ACE and $2.2 million for DPL.  The other postretirement net periodic benefit cost for the three months ended March 31, 2007, of $11.0 million includes $4.9 million for Pepco, $2.5 million for ACE and $1.8 million for DPL.  The remaining other postretirement net periodic benefit cost is for other PHI subsidiaries.

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(7)  DEBT

In January 2008, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $5.4 million on Series 2002-1 Bonds, Class A-1 and $2.2 million on Series 2003-1.

In March 2008, Pepco re-opened its November 2007 issue of $250 million 6.5% senior notes due November 2037 collateralized by first mortgage bonds, and issued an additional $250 million in principal amount of senior notes, increasing the outstanding principal amount of the 6.5% senior notes due November 2037 to $500 million.  The net proceeds has been or will be used (a) to repay short-term debt, (b) to fund the retirement of $78 million of 6.5% first mortgage bonds on March 15, 2008, (c) to repay $50 million of 5.875% first mortgage bonds due October 15, 2008 at maturity, and (d) for general corporate purposes.  In connection with the offering, Pepco agreed that for so long as the senior notes are outstanding they will remain secured by a corresponding series of first mortgage bonds.

In March 2008, DPL entered into a $150 million, unsecured two year bank loan agreement.  Interest on the loan is based on LIBOR plus an applicable margin, which varies according to DPL’s credit rating. The net proceeds were used to repay short-term debt.

In March 2008, PHI subsidiaries purchased the following series of insured tax-exempt auction rate bonds that were issued by municipal authorities for the benefit of the PHI subsidiaries.  These purchases were made in response to disruption in the market for municipal auction rate securities that made it difficult for the remarketing agent to successfully remarket the bonds:

·   DPL purchased the following series of bonds issued by The Delaware Economic Development Authority: (i) $27.75 million of Exempt Facilities Revenue Refunding Bonds 2000B Series due 2030, (ii) $15 million of Exempt Facilities Revenue Refunding Bonds 2003A Series due 2038, and (iii) $15 million of Exempt Facilities Revenue Refunding Bonds 2002A Series due 2032.

·   ACE purchased $25 million of Pollution Control Revenue Refunding Bonds 2004A Series due 2029 issued by Cape May County.

Although these bonds are considered to be extinguished for accounting purposes, DPL and ACE intend to hold the bonds, while monitoring the market and evaluating the options for remarketing the bonds to the public.

In March 2008, ACE retired at maturity $15 million of medium-term notes with a weighted average interest rate of 6.79%.

For the reason discussed above, PHI subsidiaries in April 2008 purchased the following additional series of insured tax-exempt auction rate bonds:

· Pepco purchased $109.5 million of Pollution Control Revenue Refunding Bonds Series 2006 due 2022 issued by the Maryland Economic Development Corporation.

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· DPL purchased the following series of bonds issued by the Delaware Economic Development Authority: (i) $20 million of Exempt Facilities Revenue Refunding Bonds 2001A Series due 2031, (ii) $4.5 million of Exempt Facilities Revenue Refunding Bonds 2001B Series due 2031 and (iii) $11.15 million of Exempt Facilities Revenue Refunding Bonds 2000A Series due 2030.

· ACE purchased (i) $23.15 million of Pollution Control Revenue Refunding Bonds Series 2004A due 2029 issued by Salem County and (ii) $6.5 million of Pollution Control Revenue Refunding Bonds Series 2004B due 2029 issued by Cape May County.

These bonds are also considered to be extinguished for accounting purposes, however, each of the companies intends to hold the bonds, while monitoring the market and evaluating the options for remarketing the bonds to the public.

In May 2008, Pepco completed two $25 million short-term bank loans, one maturing on September 30, 2008 and one on April 30, 2009.  Both are variable rate loans and Pepco has the option to repay the loans on any interest reset date without penalty.  Proceeds were used to temporarily finance the repurchase of Pepco insured tax exempt auction rate bonds.

(8)  INCOME TAXES

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

	For the Three Months Ended March 31,
	2008		2007
Federal statutory rate	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	.5		2.4
Asset removal costs	-		(.6)
State income taxes, net of federal effect	5.4		4.7
Tax credits	(.7)		(1.3)
Leveraged leases	(1.2)		(2.3)
Change in estimates and interest related to uncertain and effectively settled tax positions	(4.6)		.1
Software amortization	-		.8
Other, net	.2		(1.0)
Consolidated Effective Income Tax Rate	34.6	%	37.8	%

PHI’s effective tax rates for the years ended March 31, 2008 and 2007 were 34.6% and 37.8%, respectively.  The decrease in the effective tax rate in 2008 was primarily related to interest accrued on a tax claim filed with the IRS in March 2008.  The claim is for the treatment of casualty losses as current deductions (as opposed to being depreciated over their tax lives) on prior year returns currently under audit.

(9)  STOCK-BASED COMPENSATION

No stock options were granted in the three months ended March 31, 2008.

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Cash received from options exercised under all share-based payment arrangements for the three months ended March 31, 2008, was $.8 million and the actual tax benefit realized for the tax deductions resulting from these options exercised totaled $.2 million.

(10) EARNINGS PER SHARE

Reconciliations of the numerator and denominator for basic and diluted earnings per share of common stock calculations are shown below.

	For the Three Months Ended March 31,
			2008		2007
	(In millions, except per share data)
Income (Numerator):
Net Income		$	99.2	$	51.6
Add:    Loss on redemption of subsidiary’s preferred stock			-		(.6)
Earnings Applicable to Common Stock		$	99.2	$	51.0
Shares (Denominator) (a):
Weighted average shares outstanding for basic computation:
Average shares outstanding			201.0		192.5
Adjustment to shares outstanding			(.3)		(.2)
Weighted Average Shares Outstanding for Computation of   Basic Earnings Per Share of Common Stock			200.7		192.3
Net effect of potentially dilutive shares			.2		.4
Weighted Average Shares Outstanding for Computation of   Diluted Earnings Per Share of Common Stock			200.9		192.7
Basic earnings per share of common stock		$	.49	$	.27
Diluted earnings per share of common stock		$	.49	$	.27

(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 5,000 and 9,000 for the three months ended March 31, 2008 and 2007, respectively.

(11)  FAIR VALUE DISCLOSURES

Effective January 1, 2008, PHI adopted SFAS No. 157 (as discussed herein in Note 3), which established a framework for measuring fair value and expands disclosures about fair value measurements.

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).  PHI utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.  These inputs can be readily observable, market corroborated, or generally unobservable.  Accordingly, PHI utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  PHI is able to classify fair value balances based on the observability of those inputs.  SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical

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assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).  The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

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

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

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources.  Level 3 includes those financial instruments that are valued using models or other valuation methodologies.  Significant valuation inputs may have originated from internally developed methodologies that result in management’s best estimate of fair value.  Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs.  At each balance sheet date, PHI performs an analysis of all instruments subject to SFAS No. 157 and includes in level 3 all of those whose fair value is based on significant unobservable inputs.

On February 12, 2008, the FASB issued FSP No. 157-2, “Effective Date of FASB Statement No. 157” (FSP No. 157-2), which defers the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually).  FSP No. 157-2 defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008.  PHI assets and liabilities that currently meet the deferral requirements of FSP No. 157-2 are Goodwill and Asset Retirement Obligations.

The following table sets forth by level within the fair value hierarchy the company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2008.  As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  PHI's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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	Fair Value Measurements at Reporting Date Using
	(Millions of dollars)
Description	March 31, 2008	Quoted Prices in Active Markets for Identical Instruments (Level 1)	Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level  3)
ASSETS
Derivative Instruments	$326.8	$14.9	$270.7	(a)	$  41.2
Executive deferred   compensation plan assets	66.4	-	49.1		17.3
	$393.2	$14.9	$319.8		$  58.5
LIABILITIES
Derivative Instruments	$  85.8	$ 8.4	$  74.6		$   2.8
Executive deferred   compensation plan liabilities	51.5	-	51.5		-
	$137.3	$ 8.4	$126.1		$   2.8

(a) Includes contra-asset balance of $27.4 million related to the impact of netting certain counterparties across the levels of the fair value hierarchy.

A reconciliation of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (Level 3) is shown below (in millions of dollars):

	Net Derivative Instruments	Deferred Compensation Plan Assets
Beginning balance as of January 1, 2008	$  (2.6)	$17.1
Total gains or (losses) (realized/unrealized)
Included in earnings (or changes in net assets)	2.5	.7
Included in other comprehensive income	35.9	-
Purchases, issuances and settlements	2.6	(.5)
Transfers in and/or out of Level 3	-	-
Ending balance as of March 31, 2008	$ 38.4	$17.3
The amount of total gains for the period included in earnings (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at the reporting date.	$   5.3	$    .7
Gains or (losses) (realized and unrealized) included in earnings (or changes in net assets) for the period above are reported in Operating Revenue and Other Operation and Maintenance Expense as follows:
	Operating Revenue	Other Operation and Maintenance Expense
Total gains included in earnings (or changes in net assets) for the period above	$2.5	$    .7
Change in unrealized gains relating to assets still held at reporting date	$5.3	$    .7

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(12)  COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Proceeds from Settlement of Mirant Bankruptcy Claims

In 2000, Pepco sold substantially all of its electricity generating assets to Mirant and certain of its subsidiaries.  In 2003, Mirant commenced a voluntary bankruptcy proceeding in which it sought to reject certain obligations that it had undertaken in connection with the asset sale.  As part of the sale, Pepco and Mirant entered into a “back-to-back” arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco is obligated to purchase annually through 2021 from Panda under the Panda PPA at the purchase price Pepco is obligated to pay to Panda.  In connection with the settlement of Pepco’s claims against Mirant arising from the Mirant bankruptcy, Pepco agreed not to contest the rejection by Mirant of its obligations under the “back-to-back” arrangement in exchange for the payment by Mirant of damages corresponding to the estimated amount by which the purchase price that Pepco is obligated to pay Panda for the energy and capacity exceeded the market price.  In 2007, Pepco received as damages $413.9 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant.  These funds are being accounted for as restricted cash based on management’s intent to use such funds, and any interest earned thereon, for the sole purpose of paying for the future above-market capacity and energy purchase costs under the Panda PPA.  Correspondingly, a regulatory liability has been established in the same amount to help offset the future above-market capacity and energy purchase costs.  This restricted cash has been classified as a non-current asset to be consistent with the classification of the non-current regulatory liability, and any changes in the balance of this restricted cash, including interest on the invested funds, are being accounted for as operating cash flows.

As of March 31, 2008, the balance of the restricted cash account was $415.4 million.  Based on a reexamination of the costs of the Panda PPA in light of current and projected wholesale market conditions conducted in the fourth quarter of 2007, Pepco determined that, principally due to increases in wholesale capacity prices, the present valueabove-market cost of the Panda PPA over the term of the agreement is expected tobe significantly less than the current amount of the restricted cash account balance.  Accordingly, on February 22, 2008, Pepco filed applications with the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC) requesting orders directing Pepco to maintain $320 million in the restricted cash account and to use that cash, and any future earnings on the cash, for the sole purpose of paying the future above-market cost of the Panda PPA (or, in the alternative, to either fund a transfer or assignment of the remaining obligations under the Panda PPA to a third party or pay Panda to terminate the Panda PPA).  Pepco also requested that the order provide that any cash remaining in the account at the conclusion of the Panda PPA be refunded to customers and that any shortfall be recovered from customers.  Pepco further proposed that the excess proceeds remaining from the settlement (approximately $94.6 million, representing the amount by which the regulatory liability of $414.6 million at December 31, 2007 exceeded $320 million) be shared approximately equally with its customers in accordance with the procedures previously approved by each commission for the sharing of the proceeds received by Pepco from the sale to Mirant of its generating assets.  The amount of the restricted cash balance that Pepco is permitted to retain will be recorded as earnings upon approval of the sharing arrangement by the respective commissions.  At this time, Pepco cannot predict the outcome of these proceedings.

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Rate Proceedings

In electric service distribution base rate cases filed by Pepco in the District of Columbia and Maryland, and by DPL in Maryland, Pepco and DPL proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers.  Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the approved revenue-per-customer amount.  The BSA will increase rates if actual distribution revenues fall below the level approved by the applicable commission and will decrease rates if actual distribution revenues are above the approved level.  The result will be that, over time, the utility would 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 the regulated utilities to promote energy efficiency programs for their customers, because it breaks the link between overall sales volumes and delivery revenues.  The status of the BSA proposals in each of the jurisdictions is described below in the context of the respective base rate proceedings.

District of Columbia

In December 2006, Pepco submitted an application to the DCPSC to increase electric distribution base rates, including a proposed BSA.  On January 30, 2008, the DCPSC approved, effective February 20, 2008, a revenue requirement increase of approximately $28.3 million, based on an authorized return on rate base of 7.96%, including a 10% return on equity (ROE).  While finding the BSA to be an appropriate ratemaking concept, the DCPSC cited potential statutory problems in its authority to implement the BSA.  On February 28, 2008, the DCPSC established a Phase II proceeding to consider these implementation issues.  Initial briefs were filed on March 31, 2008; reply briefs were filed April 15, 2008.

Maryland

On July 19, 2007, the MPSC issued orders in the electric service distribution rate cases filed by DPL and Pepco, each of which included approval of a BSA.  The DPL order approved an annual increase in distribution rates of approximately $14.9 million (including a decrease in annual depreciation expense of approximately $.9 million).  The Pepco order approved an annual increase in distribution rates of approximately $10.6 million (including a decrease in annual depreciation expense of approximately $30.7 million).  In each case, the approved distribution rate reflects an ROE of 10.0%.  The rate increases were effective as of June 16, 2007, and remained in effect for an initial period until April 19, 2008.  On March 14, 2008, the MPSC extended this initial period to July 19, 2008.  These rates are subject to a Phase II proceeding in which the MPSC will consider the results of audits of each company’s cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates is required.  Evidentiary hearings were held in mid-March 2008.  Initial briefs were filed on March 26, 2008 and reply briefs were filed April 7, 2008.

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New Jersey

On June 1, 2007, ACE filed with the New Jersey Board of Public Utilities (NJBPU) an application for permission to decrease the Non Utility Generation Charge (NGC) and increase components of its Societal Benefits Charge (SBC) to be collected from customers for the period October 1, 2007 through September 30, 2008.  The proposed changes are designed to effect a true-up of the actual and estimated costs and revenues collected through the current NGC and SBC rates through September 30, 2007 and, in the case of the SBC, forecasted costs and revenues for the period October 1, 2007 through September 30, 2008.

As of March 31, 2008, the NGC, which is intended primarily to recover the above-market component of payments made by ACE under non-utility generation contracts and stranded costs associated with those commitments, had an over-recovery balance of $247.5 million.  The filing proposed that the estimated NGC balance as of September 30, 2007 in the amount of $216.2 million, including interest, be amortized and returned to ACE customers over a four-year period, beginning October 1, 2007.

As of March 31, 2008, the SBC, which is intended to allow ACE to recover certain costs involved with various NJBPU-mandated social programs, had an under-recovery of approximately $24.3 million, primarily due to increased costs associated with funding the New Jersey Clean Energy Program.  In addition, ACE has requested an increase to the SBC to reflect the funding levels approved by the NJBPU of $20.4 million for the period October 1, 2007 through September 30, 2008, bringing to $40 million the total recovery requested for the period October 1, 2007 to September 30, 2008 (based upon actual data through August 2007).

The net impact of the proposed adjustments to the NGC and the SBC, including associated changes in sales and use tax, is an overall distribution rate decrease of approximately $117.3 million as of March 31, 2009, for the period June 1, 2008 through May 31, 2009 (the final rate changes will be based upon actual data through March 2008).  A Stipulation of Settlement (the Stipulation) memorializing the terms of a negotiated resolution has been executed by NJBPU staff, the New Jersey Division of Rate Counsel and ACE.  The Stipulation reflects negotiated adjustments that reduce the amount ACE will recover from customers by approximately $1.1 million as part of a compromise offer, and the associated rate decrease shown above.  The Stipulation is subject to the approval of the NJBPU.  On May 1, 2008, the administrative law judge in the proceeding recommended that the NJBPU approve the Stipulation, which is scheduled for NJBPU consideration on May 8, 2008.  If the Stipulation is approved by the NJBPU and implemented, ACE anticipates that the revised rates will remain in effect until May 31, 2009, subject to an annual true-up and change each year thereafter.

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 elect to purchase electricity from a competitive 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

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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 $195.0 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 2005, an additional $1.2 million in interest on the disallowed amount was identified and reserved by ACE.  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.  On August 9, 2007, the Appellate Division, citing deference to the factual and policy findings of the NJBPU, affirmed the NJBPU’s decision in its entirety, rejecting challenges from ACE and the Division of Rate Counsel.  On September 10, 2007, ACE filed an application for certification to the New Jersey Supreme Court.  On January 15, 2008, the New Jersey Supreme Court denied ACE’s application for certification.  Because the full amount at issue in this proceeding was previously reserved by ACE, there will be no further financial statement impact to ACE.

Divestiture Cases

District of Columbia

In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets.  An unresolved issue relating to the application filed with the DCPSC by Pepco to implement the divestiture settlement is whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code (IRC) and its

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implementing regulations.  As of March 31, 2008, 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 by Pepco, there is no book life over which the EDIT and ADITC can be returned.  If Pepco were required to share EDIT and ADITC and, as a result, the normalization rules were violated, Pepco would be unable to use accelerated depreciation on District of Columbia allocated or assigned property.  In addition to sharing with customers the generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS an amount equal to Pepco’s District of Columbia jurisdictional generation-related ADITC balance ($5.8 million as of March 31, 2008), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance $3.9 million as of March 31, 2008) 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.

On March 6, 2008, the IRS approved final regulations, effective March 20, 2008, which allow utilities whose assets cease to be utility property (whether by disposition, deregulation or otherwise) to return to its utility customers the normalization reserve for EDIT and part or all of the normalization reserve for ADITC.  This ruling applies to assets divested after December 21, 2005.  For utility property divested on or before December 21, 2005, the IRS stated that it would continue to follow the holdings set forth in private letter rulings prohibiting the flow through of EDIT and ADITC associated with the divested assets.  Pepco made a filing on April 22, 2008, advising the DCPSC of the adoption of the final regulations and requesting that the DCPSC issue an order consistent with the IRS position.  If the DCPSC issues the requested order, no accounting adjustments to the gain recorded in 2000 would be required.  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 March 31, 2008, the Maryland allocated portions of EDIT and

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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 (as discussed above) 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 March 31, 2008), 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 March 31, 2008), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($6.9 million as of March 31, 2008), 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.

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, pending completion of the IRS rulemaking regarding sharing of EDIT and ADITC related to divested assets.  Pepco made a filing on April 22, 2008, advising the MPSC of the adoption of the final IRS normalization regulations (described above under “Divestiture Cases -- District of Columbia”) and requesting that the MPSC issue a ruling on the appeal consistent with the IRS position.  If the MPSC issues the requested ruling, no accounting adjustments to the gain recorded in 2000 would be required.  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.

ACE Sale of B.L. England Generating Facility

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 which it received proceeds of approximately $9 million.  At the time of the sale, RC Cape May and ACE agreed to submit to arbitration the issue of whether RC Cape May, under the terms of the purchase agreement, must pay to ACE an additional $3.1 million as part of the purchase price.  On February 26, 2008, the arbitrators issued a decision awarding $3.1 million to ACE, plus interest, attorneys’ fees and costs, for a total award of approximately $4.2 million.

On July 18, 2007, ACE received a claim for indemnification from RC Cape May under the purchase agreement.  RC Cape May contends that one of the assets it purchased, a contract for terminal services (TSA) between ACE and Citgo Asphalt Refining Co. (Citgo), has been declared by Citgo to have been terminated due to a failure by ACE to renew the contract in a timely manner.  RC Cape May has commenced an arbitration proceeding against Citgo seeking

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a determination that the TSA remains in effect and has notified ACE of the proceeding.  In addition, RC Cape May has asserted a claim for indemnification from ACE in the amount of $25 million if the TSA is held not to be enforceable against Citgo.  While ACE believes that it has defenses to the indemnification claims, should the arbitrator rule that the TSA has terminated, the outcome of this matter is uncertain.  ACE notified RC Cape May of its intent to participate in the pending arbitration.

The sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized.  In accordance with an NJBPU order dated April 16, 2008, the net proceeds from the sale of the plant and monetization of the emission allowance credits, estimated to be $39.9 million as of May 31, 2008, will be credited to ACE’s customers, over a period of approximately12 monthsbeginning on June 1, 2008.

DPL Sale of Virginia Operations

On January 2, 2008, DPL completed (i) the sale of its retail electric distribution business on the Eastern Shore of Virginia to A&N Electric Cooperative (A&N) for a purchase price of approximately $48.8 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission business located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase price of approximately $5.4 million, after closing adjustments.  Each of A&N and ODEC assumed certain post-closing liabilities and unknown pre-closing liabilities related to the respective assets they purchased (including, in the A&N transaction, most environmental liabilities), except that DPL remained liable for unknown pre-closing liabilities if they become known within six months after the January 2, 2008 closing date.  These sales resulted in a $3.1 million pre-tax gain ($1.8 million after-tax), which was recorded in the first quarter of 2008.  In accordance with the purchase and sale agreements, the final closing adjustments will be recorded in the second quarter of 2008.

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 March 31, 2008, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant for defense and indemnification

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pursuant to the terms of the Asset Purchase and Sale Agreement between Pepco and Mirant under which Pepco sold its generation assets to Mirant in 2000.

While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) is approximately $360 million, PHI and Pepco believe the amounts claimed by 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 PHI’s noncontributory retirement plan (the PHI Retirement Plan).  In September 2005, three management employees of PHI Service Company filed suit in the U.S. 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-legacy employees who were not eligible for grandfathered benefits.

The plaintiffs challenged the design of the Cash Balance Sub-Plan and sought a declaratory judgment that the Cash Balance Sub-Plan was 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 alleged that the use of a variable rate to compute the plaintiffs’ accrued benefit under the Cash Balance Sub-Plan resulted in reductions in the accrued benefits that violated ERISA.  The complaint also alleged that the benefit accrual rates and the minimal accrual requirements of the Cash Balance Sub-Plan violated ERISA as did the notice that was given to plan participants upon implementation of the Cash Balance Sub-Plan.

On September 19, 2007, the Delaware District Court issued an order granting summary judgment in favor of the PHI Parties.  On October 12, 2007, the plaintiffs filed an appeal of the decision to the U.S. Court of Appeals for the Third Circuit and the parties completed the filing of briefs on March 17, 2008.

If the plaintiffs were to prevail in this litigation, 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

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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.

Delilah Road Landfill Site.  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 with NJDEP to remediate the site.  The soil cap remedy for the site has been implemented and in August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site.  Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years.  In September 2007, NJDEP approved the PRP group’s petition to conduct semi-annual, rather than quarterly, ground water monitoring for two years and deferred until the end of the two-year period a decision on the PRP group’s request for annual groundwater monitoring thereafter.  In August 2007, the PRP group agreed to reimburse the U.S. Environmental Protection Agency’s (EPA’s) costs in the amount of $81,400 in full satisfaction of EPA’s claims for all past and future response costs relating to the site (of which ACE’s share is one-third) and in October 2007, EPA and the PRP group entered into a tolling agreement to permit the parties sufficient time to execute a final settlement agreement.  This settlement agreement, with an April 11, 2008 effective date, will allow EPA to reopen the settlement in the event of new information or unknown conditions at the site.  Based on information currently available, ACE anticipates that its share of additional cost associated with this site for post-remedy operation and maintenance will be approximately $555,000 to $600,000.  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.

Frontier Chemical Site.  On June 29, 2007, ACE received a letter from the New York Department of Environmental Conservation (NYDEC) identifying ACE as a PRP at the Frontier Chemical Waste Processing Company site in Niagara Falls, N.Y. based on hazardous waste manifests indicating that ACE sent in excess of 7,500 gallons of manifested hazardous waste to the site.  ACE has entered into an agreement with the other parties identified as PRPs to form the PRP group and has informed NYDEC that it has entered into good faith negotiations with the PRP group to address ACE’s responsibility at the site.  ACE believes that its responsibility at the site will not have a material adverse effect on its financial position, results of operations or cash flows.

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Carolina Transformer Site.  In August 2006, EPA notified each of DPL and Pepco that they have been identified as entities that sent PCB-laden oil to be disposed at the Carolina Transformer site in Fayetteville, North Carolina.  The EPA notification stated that, on this basis, DPL and Pepco may be PRPs.  In December 2007, DPL and Pepco agreed to enter into a settlement agreement with EPA and the PRP group at the Carolina Transformer site.  In the first quarter 2008, the State of North Carolina indicated its intent to join in the settlement agreement as a party plaintiff.  Under the terms of the settlement, (i) Pepco and DPL each paid $162,000 to resolve any liability that it might have at the site to EPA and the State of North Carolina, (ii) EPA and the State of North Carolina covenant not to sue or bring administrative action against DPL and Pepco for response costs at the site, (iii) other PRP group members release all rights for cost recovery or contribution claims they may have against DPL and Pepco, and (iv) DPL and Pepco release all rights for cost recovery or contribution claims that they may have against other parties settling with EPA and the State of North Carolina.  The consent decree is expected to be filed with the U.S. District Court in North Carolina in the second quarter of 2008.

Deepwater Generating Station.  In December 2005, NJDEP issued a Title V Operating Permit for Conectiv Energy’s Deepwater Generating Station.  The permit includes new limits on unit heat input.  In order to comply with these new operational limits, Conectiv Energy restricted the output of the Deepwater Generating Station’s Unit 1 and Unit 6.  In 2006 and the first half of 2007, these restrictions resulted in lost revenues of approximately $10,000 per operating day on Unit 6, primarily due to reduced output, and to a lesser degree due to capacity requirements of PJM.  Since June 1, 2007, Deepwater Unit 6 has been able to operate within the heat input limits set forth in the Title V Operating Permit without restricting output, by partially correcting the inherent bias in the continuous emissions monitoring system that had caused recorded heat input to be higher than actual heat input.  In order to comply with the heat input limit at Deepwater Unit 1, Conectiv Energy continues to restrict Unit 1 output, resulting in penalties and lost revenues related to PJM capacity requirements of approximately $103,000 in the first quarter of 2008, and projected penalties and lost revenues related to PJM capacity requirements of $69,000 for the balance of 2008.  Beyond 2008, while penalties due to PJM capacity requirements are not expected, further lost revenues related to PJM capacity requirements may continue to be incurred.  The lost revenues due to reduced output on Unit 1 have been, and are expected to continue to be, insignificant.  Conectiv Energy is challenging these heat input restrictions and other provisions of the Title V Operating Permit for Deepwater Generating Station in the New Jersey Office of Administrative Law (OAL).  On October 2, 2007, the OAL issued a decision granting summary decision in favor of Conectiv Energy, finding that hourly heat input shall not be used as a condition or limit for Conectiv Energy’s electric generating operations.  On October 26, 2007, the NJDEP Commissioner denied NJDEP’s request for interlocutory review of the OAL order and determined that the Commissioner would review the October 2, 2007 order upon completion of the proceeding on Conectiv Energy’s challenges to certain fuel use limits and stack testing requirements in the Deepwater Title V permit.  A hearing on the remaining challenged Title V permit provisions is scheduled for June 24, 2008.

On April 3, 2007, NJDEP issued an Administrative Order and Notice of Civil Administrative Penalty Assessment (the First Order) alleging that at Conectiv Energy's Deepwater Generating Station, the maximum gross heat input to Unit 1 exceeded the maximum allowable heat input in calendar year 2005 and the maximum gross heat input to Unit 6 exceeded the maximum allowable heat input in calendar years 2005 and 2006.  The order

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required the cessation of operation of Units 1 and 6 above the alleged permitted heat input levels and assessed a penalty of approximately $1.1 million.  On May 23, 2007, NJDEP issued a second Administrative Order and Notice of Civil Administrative Penalty Assessment (the Second Order) alleging that the maximum gross heat input to Units 1 and 6 exceeded the maximum allowable heat input in calendar year 2004.  The Second Order required the cessation of operation of Units 1 and 6 above the alleged permitted heat input levels and assessed a penalty of $811,600.  Conectiv Energy has requested a contested case hearing challenging the issuance of the First Order and the Second Order and moved for a stay of the orders pending resolution of the Title V Operating Permit contested case described above.  On November 29, 2007, the OAL issued orders placing the First Order and the Second Order on the inactive list for six months.

IRS Examination of Like-Kind Exchange Transaction

In 2001, Conectiv and certain of its subsidiaries (the Conectiv Group) were engaged in the implementation of a strategy to divest non-strategic electric generating facilities and replace 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 a revenue agent’s report (RAR) for the audit of Conectiv’s 2000, 2001 and 2002 income tax returns, in which the IRS 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 is contesting 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.  PHI has accrued approximately $5.2 million of interest reserves related to this matter.

As of March 31, 2008, if the IRS were to fully prevail, the potential cash impact on PHI would be current income tax and interest payments of approximately $29.3 million and the earnings impact would be approximately $10.3 million in after-tax interest.

Federal Tax Treatment of Cross-Border Leases

PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which, as of March 31, 2008, had a book value of approximately $1.4 billion, and from which PHI currently derives approximately $62 million per year in tax benefits in the form of interest and depreciation deductions.

In 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.,

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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.  Also in 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.  In June 2006, the IRS issued its final 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 March 31, 2008 were approximately $362 million.  PHI has filed a protest against the IRS adjustments and the unresolved audit has been forwarded to the U.S. Office of Appeals.  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 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.

In 2006, the FASB issued FSP 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 December 14, 2007 the U.S. Senate passed its version of the Farm, Nutrition, and Bioenergy Act of 2007 (H.R. 2419) which contains a provision that 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.  The U.S. House of Representatives version of this proposed legislation which it passed on July 27, 2007 does not contain 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 PHI would receive in connection with its cross-border energy leases.  Furthermore, if legislation of this type were to be enacted, under FSP FAS 13-2, PHI would be required to adjust the book value of the leases and record a charge to earnings equal to the repricing impact of the deferred 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 currently in conference to reconcile the differences in the two bills to determine the final legislation.

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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.

In 2005, the Treasury Department issued proposed 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 the proposed 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.

At the same time as the proposed 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 additional taxes and interest that management estimated to be payable for the years 2001 through 2004 based on the method of tax accounting that PHI, pursuant to the proposed regulations, 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.  It is reasonably possible that PHI’s unrecognized tax benefits related to this issue will significantly decrease in the next 12 months as a result of a settlement with the IRS.

Third Party Guarantees, Indemnifications, Obligations 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 March 31, 2008, Pepco Holdings and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, performance residual value, and other commitments and obligations.  The commitments and obligations, in millions of dollars, were as follows:

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	Guarantor
		PHI		DPL		ACE		Other		Total
Energy marketing obligations of Conectiv Energy (a)	$	254.9	$	-	$	-	$	-	$	254.9
Energy procurement obligations ofPepco Energy Services (a)		109.0		-		-		-		109.0
Guaranteed lease residual values (b)		-		2.6		2.5		.6		5.7
Other (c)		2.2		-		-		1.3		3.5
Total	$	366.1	$	2.6	$	2.5	$	1.9	$	373.1

(a)	Pepco Holdings has contractual commitments for performance and related payments of Conectiv Energy and Pepco Energy Services to counterparties under routine energy sales and procurement obligations, including retail customer load obligations of Pepco Energy Services and requirements under BGS contracts entered into by Conectiv Energy with ACE.
(b)	Subsidiaries of Pepco Holdings have guaranteed residual values in excess of fair value of certain equipment and fleet vehicles held through lease agreements. As of March 31, 2008, obligations under the guarantees were approximately $5.7 million. Assets leased under agreements subject to residual value guarantees are typically for periods ranging from 2 years to 10 years. Historically, payments under the guarantees have not been made by the guarantor as, under normal conditions, the contract runs to full term at which time the residual value is minimal. As such, Pepco Holdings believes the likelihood of payment being required under the guarantee is remote.
(c)	Other guarantees consist of:

· Pepco Holdings has guaranteed a subsidiary building lease of $2.2 million. Pepco Holdings does not expect to fund the full amount of the exposure under the guarantee.  

· PCI has guaranteed facility rental obligations related to contracts entered into by Starpower Communications, LLC, a joint venture in which PCI prior to December 2004 had a 50% interest. As of March 31, 2008, the guarantees cover the remaining $1.3 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 indemnities.

Dividends

On April 24, 2008, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable June 30, 2008, to shareholders of record on June 10, 2008.

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

PHI accounts for its derivative activities in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133) as amended by subsequent pronouncements.  See “Summary of Significant Accounting Policies -- Accounting for Derivatives” in Note (2) and “Use of Derivatives in Energy and Interest Rate Hedging Activities” in Note (13) to the Consolidated Financial Statements of PHI included in PHI’s Annual Report on Form 10-K for the year ended December 31, 2007, for a discussion of the accounting treatment of the derivatives used by PHI and its subsidiaries.

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The table below provides detail on effective cash flow hedges under SFAS No. 133 included in PHI’s Consolidated Balance Sheet as of March 31, 2008.  Under SFAS No. 133, cash flow hedges are marked-to-market on the balance sheet with corresponding adjustments to Accumulated Other Comprehensive Income (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 Income As of March 31, 2008 (Millions of dollars)
Contracts	Accumulated OCI (Loss) After Tax (a)		Portion Expected to be Reclassified to Earnings during the Next 12 Months		Maximum     Term
Other Energy Commodity	$	109.4	$	98.9	50 months
Interest Rate		(28.0)		(3.3)	293 months
Total	$	81.4	$	95.6

(a) Accumulated Other Comprehensive Income as of March 31, 2008, includes a $(7.3) 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.

The following table shows, in millions of dollars, the pre-tax gain (loss) recognized in earnings for cash flow hedge ineffectiveness for the three months ended March 31, 2008 and 2007 and where they were reported in PHI’s Consolidated Statements of Earnings during the periods.

	2008		2007
Operating Revenue	$	(2.7)	$	(.6)
Fuel and Purchased Energy Expenses		5.8		(.3)
Total	$	3.1	$	(.9)

In connection with their other energy commodity activities, the Competitive Energy businesses designate certain derivatives as fair value hedges.  The net pre-tax gains (losses) recognized during the three months ended March 31, 2008 and 2007, and 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).

		2008		2007
Loss on Derivative Instruments	$	(10.8)	$	(1.8)
Gain on Hedged Items	$	11.3	$	1.6

For the three months ended March 31, 2008, a $.4 million gain was reclassified from Other Comprehensive Income (OCI) to earnings because the forecasted hedged transactions were deemed to be no longer probable.  For the three months ended March 31, 2007, a $1.2 million gain was reclassified from OCI to earnings because the forecasted hedged transactions were deemed to be no longer probable.

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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 three months ended March 31, 2008 and 2007.

	2008		2007
Proprietary Trading (a)	$	-	$	-
Other Energy Commodity (b)		44.0		8.0
Total	$	44.0	$	8.0

(a)	PHI does not engage in proprietary trading.
(b)	Includes $.6 million of ineffective fair value hedge losses for the three months ended March 31, 2008, and $.4 million of ineffective fair value hedge gains for the three months ended March 31, 2007.

As indicated at Note 3, PHI offsets the fair value amounts recognized for derivative instruments and fair value amounts recognized for related collateral positions executed with the same counterparty under a master netting arrangement. The amount of cash collateral that was offset against these net derivative positions is as follows:

	March 31, 2008		December 31, 2007
	(Millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	23.4	$	-
Cash collateral received from counterparties with the obligation to return		62.1		-

As of March 31, 2008 and December 31, 2007, PHI had no cash collateral pledged or received that was not eligible for offset under master netting arrangements.

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POTOMAC ELECTRIC POWER COMPANY STATEMENTS OF EARNINGS (Unaudited)
		Three Months Ended March 31,
		2008		2007
		(Millions of dollars)
Operating Revenue	$	524.5	$	506.6
Operating Expenses
Fuel and purchased energy		307.5		296.5
Other operation and maintenance		70.3		71.0
Depreciation and amortization		34.4		41.9
Other taxes		69.6		68.3
Gain on sale of assets		-		(.6)
Total Operating Expenses		481.8		477.1
Operating Income		42.7		29.5
Other Income (Expenses)
Interest and dividend income		4.0		.5
Interest expense		(24.0)		(18.5)
Other income		2.8		3.1
Other expenses		(.1)		(.1)
Total Other Expenses		(17.3)		(15.0)
Income Before Income Tax Expense		25.4		14.5
Income Tax Expense		10.2		5.8
Net Income		15.2		8.7
Retained Earnings at Beginning of Period		596.9		559.7
Dividends Paid to Pepco Holdings		(20.0)		(15.0)
Cumulative Effect Adjustment Related to   the Implementation of FIN 48		-		(1.9)
Retained Earnings at End of Period	$	592.1	$	551.5

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

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POTOMAC ELECTRIC POWER COMPANY BALANCE SHEETS (Unaudited)
ASSETS		March 31, 2008		December 31, 2007
	(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$	61.2	$	19.0
Restricted cash			8.5		1.2
Accounts receivable, less allowance for  uncollectible accounts     of $11.4 million and $12.5 million, respectively			322.9		343.5
Materials and supplies - at average cost			50.0		45.4
Prepayments of income taxes			93.4		93.4
Prepaid expenses and other			15.4		15.1
Total Current Assets			551.4		517.6
INVESTMENTS AND OTHER ASSETS
Regulatory assets			181.5		178.5
Prepaid pension expense			149.7		152.0
Investment in trust			26.8		26.5
Income taxes receivable			172.3		171.2
Restricted cash and cash equivalents			415.4		417.3
Other			94.7		75.4
Total Investments and Other Assets			1,040.4		1,020.9
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			5,412.7		5,368.9
Accumulated depreciation			(2,293.0)		(2,274.4)
Net Property, Plant and Equipment			3,119.7		3,094.5
TOTAL ASSETS		$	4,711.5	$	4,633.0

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

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POTOMAC ELECTRIC POWER COMPANY BALANCE SHEETS (Unaudited)
LIABILITIES AND SHAREHOLDER’S EQUITY		March 31, 2008		December 31, 2007
	(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt		$	-	$	179.9
Current maturities of long-term debt			100.0		128.0
Accounts payable and accrued liabilities			179.9		201.7
Accounts payable to associated companies			68.2		75.8
Capital lease obligations due within one year			6.0		6.0
Taxes accrued			85.2		90.1
Interest accrued			33.4		17.0
Liabilities and accrued interest related to uncertain tax positions			67.9		67.8
Other			100.5		88.9
Total Current Liabilities			641.1		855.2
DEFERRED CREDITS
Regulatory liabilities			544.3		542.4
Deferred income taxes, net			641.4		619.2
Investment tax credits			12.0		12.5
Other postretirement benefit obligation			57.8		57.4
Income taxes payable			130.4		129.0
Other			71.8		70.1
Total Deferred Credits			1,457.7		1,430.6
LONG-TERM LIABILITIES
Long-term debt			1,304.1		1,111.7
Capital lease obligations			105.1		105.2
Total Long-Term Liabilities			1,409.2		1,216.9
COMMITMENTS AND CONTINGENCIES  (NOTE 10)
SHAREHOLDER’S EQUITY
Common stock, $.01 par value, authorized     200,000,000 shares, issued 100 shares			-		-
Premium on stock and other capital contributions			611.4		533.4
Retained earnings			592.1		596.9
Total Shareholder’s Equity			1,203.5		1,130.3
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY		$	4,711.5	$	4,633.0

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

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POTOMAC ELECTRIC POWER COMPANY STATEMENTS OF CASH FLOWS (Unaudited)
		Three Months Ended March 31,
			2008		2007
	(Millions of dollars)
OPERATING ACTIVITIES
Net income		$	15.2	$	8.7
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization			34.4		41.9
Deferred income taxes			23.4		(2.8)
Gain on sale of assets			-		(.6)
Changes in:
Accounts receivable			20.6		(14.4)
Regulatory assets and liabilities			(5.6)		(9.1)
Accounts payable and accrued liabilities			(6.0)		28.2
Interest and taxes accrued			(6.0)		6.2
Other changes in working capital			(4.7)		(11.8)
Net other operating			7.2		6.0
Net Cash From Operating Activities			78.5		52.3
INVESTING ACTIVITIES
Net investment in property, plant and equipment			(58.5)		(67.8)
Net other investing activities			(7.7)		(.5)
Net Cash Used By Investing Activities			(66.2)		(68.3)
FINANCING ACTIVITIES
Dividends paid to Pepco Holdings			(20.0)		(15.0)
Capital contribution from Parent			78.0		-
Issuances of long-term debt			250.0		-
Reacquisition of long-term debt			(78.0)		(35.0)
(Reacquisitions) issuances of short-term debt, net			(179.9)		68.7
Net other financing activities			(20.2)		(6.5)
Net Cash From Financing Activities			29.9		12.2
Net Increase (Decrease) in Cash and Cash Equivalents			42.2		(3.8)
Cash and Cash Equivalents at Beginning of Period			19.0		12.4
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	61.2	$	8.6
NONCASH ACTIVITIES
Asset retirement obligations associated with removal costs   transferred to regulatory liabilities		$	2.9	$	1.6
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for income taxes    (includes payments to PHI for Federal income taxes)		$	2.1	$	-

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 in both the District of Columbia and Maryland.  Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (Pepco Holdings or PHI).

(2)  SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

Pepco’s unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP).  Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted.  Therefore, these financial statements should be read along with the annual financial statements included in Pepco’s Annual Report on Form 10-K for the year ended December 31, 2007.  In the opinion of Pepco’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly Pepco’s financial condition as of March 31, 2008, in accordance with GAAP.  The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.  Interim results for the three months ended March 31, 2008 may not be indicative of results that will be realized for the full year ending December 31, 2008 since the sales of electric energy are seasonal.

FIN 46R, “Consolidation of Variable Interest Entities”

Due to a variable element in the pricing structure of Pepco’s purchase power agreement with Panda-Brandywine, L.P. (Panda) entered into in 1991, pursuant to which Pepco is obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (Panda PPA), Pepco potentially assumes the variability in the operations of the plants related to the Panda PPA and therefore has a variable interest in the entity.  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) and FASB Staff Position (FSP) 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)” (FSP FIN 46(R)-6), Pepco continued, during the first quarter of 2008, 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

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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 three months ended March 31, 2008 and 2007 were approximately $20 million and $23 million, respectively.  There is no loss exposure under the Panda PPA as recovery will be achieved through the sale of purchased power into PJM Interconnection, LLC (PJM), and with the funds received from the Mirant Corporation (Mirant) bankruptcy settlement covering the amount by which the purchase cost exceeds the proceeds from the sale.

Taxes Assessed by a Governmental Authority on Revenue-producing Transactions

Taxes included in Pepco’s gross revenues were $57.1 million and $56.2 million for the three months ended March 31, 2008 and 2007, respectively.

(3)  NEWLY ADOPTED ACCOUNTING STANDARDS

SFAS No. 157, "Fair Value Measurements"

In September 2006, the FASB issued Statement of Financial Accounting Standards (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.

SFAS No. 157 nullified a portion of Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,”(EITF 02-3).  Under EITF 02-3, the transaction price presumption prohibited recognition of a trading profit at inception of a derivative unless the positive fair value of that derivative was substantially based on quoted prices or a valuation process incorporating observable inputs.  For transactions that did not meet this criterion at inception, trading profits that had been deferred were recognized in the period that inputs to value the derivative became observable or when the contract performed.  SFAS No. 157 nullified this portion of EITF 02-3.  SFAS No. 157 also: (1) establishes that fair value is based on a hierarchy of inputs into the valuation process (as described in Note 9), (2) clarifies that an issuer's credit standing should be considered when measuring liabilities at fair value, (3) precludes the use of a liquidity or blockage factor discount when measuring instruments traded in an actively quoted market at fair value and (4) requires costs relating to acquiring instruments carried at fair value to be recognized as expense when incurred.  SFAS No. 157 requires that a fair value measurement reflect the assumptions market participants would use in pricing an asset or liability based on the best available information.  These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model.

The provisions of SFAS No. 157 are to be applied prospectively, except for the initial impact on three specific items: (1) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF 02-3, (2) existing hybrid financial instruments measured initially at fair value using the transaction price and (3) blockage factor discounts.  Adjustments to these items required under SFAS No. 157 are to be recorded as a transition adjustment to beginning retained earnings in the year of adoption.

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The provisions of SFAS No. 157, as issued, are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (January 1, 2008 for Pepco).  On February 12, 2008, the FASB issued FSP No. 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” (FSP No. 157-1) that removes certain leasing transactions from the scope of SFAS No. 157.  On February 12, 2008, the FASB also issued FSP No. 157-2, “Effective Date of FASB Statement No. 157” (FSP No. 157-2) which defers the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually).  FSP No. 157-2 defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of the Final Staff Positions.

Pepco applied the guidance of FSP No. 157-1 and FSP No. 157-2 with its adoption of SFAS No. 157 on January 1, 2008.  The adoption of SFAS No. 157 did not result in a transition adjustment to beginning retained earnings and did not have a material impact on Pepco’s overall financial condition, results of operations or cash flows.  SFAS No. 157 also requires new disclosures regarding the level of pricing observability associated with financial instruments carried at fair value.  This additional disclosure is provided in Note 9, “Fair Value Disclosures,” herein.  Additionally, with the deferral of the effective date of SFAS No. 157 for certain non-financial assets and non-financial liabilities under FSP No. 157-2, Pepco does not anticipate any material changes to 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 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 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 the beginning of a reporting entity’s first fiscal year that begins after November 15, 2007 (January 1, 2008 for Pepco).  Pepco adopted the provisions of SFAS No. 159 on January 1, 2008 and chose not to elect the fair value option for its eligible financial assets and liabilities.

(4)  RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

SFAS No. 141(R), “Business Combinations – a replacement of FASB Statement No. 141”

On December 4, 2007, the FASB issued SFAS No. 141(R), “Business Combinations – a replacement of FASB Statement No. 141” (SFAS No. 141(R)) which replaces FASB Statement No. 141, “Business Combinations.”  This Statement retains the fundamental requirements in Statement 141 that the acquisition method of accounting (which Statement 141 called the purchase method) be used for all business combinations and for an acquirer to be identified for each business combination.

SFAS No. 141(R) applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree).  It does not apply to (i) the formation of a joint venture, (ii) the acquisition of an asset or a group of assets that does not constitute a business, (iii) a combination between entities or businesses under common control and (iv) a combination between not-for-profit organizations or the acquisition of a for-profit business by a not-for-profit organization.

This Statement amends FASB Statement No. 109, Accounting for Income Taxes, to require the acquirer to recognize changes in the amount of its deferred tax benefits that are recognizable because of a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances (such changes arise through the increase or reduction of the acquirer’s valuation allowance on its previously existing deferred tax assets because of the business combination).  Previously, Statement 109 required a reduction of the acquirer’s valuation allowance because of a business combination to be recognized through a corresponding reduction to goodwill.

SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for Pepco).  An entity may not apply it before that date.  Pepco is currently evaluating the impact SFAS No. 141(R) may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51”

On December 4, 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51” (SFAS No. 160), which amends ARB 51 to establish accounting and reporting standards for a noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary.  It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.

A noncontrolling interest, sometimes called a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. The objective of SFAS No. 160 is

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to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards that require (i) the ownership interests in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated statement of financial position within equity, but separate from the parent’s equity, (ii) the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of income, (iii) the changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently, and (iv) when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary must be initially measured at fair value.  The gain or loss on the deconsolidation of the subsidiary is measured using the fair value of any noncontrolling equity investment rather than the carrying amount of that retained investment and SFAS No. 160 requires entities provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.

SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for Pepco).  Earlier adoption is prohibited.  SFAS No. 160 shall be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, except for the presentation and disclosure requirements.  The presentation and disclosure requirements shall be applied retrospectively for all periods presented.  Pepco is currently evaluating the impact SFAS No. 160 may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

(5)  SEGMENT INFORMATION

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

(6)  PENSIONS AND OTHER POSTRETIREMENT BENEFITS

Pepco accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan.  PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2008, of $16.0 million includes $6.3 million for Pepco’s allocated share.  The remaining pension and other postretirement net periodic benefit cost is allocated to other PHI subsidiaries.  PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2007, of $17.0 million includes $8.1 million for Pepco’s allocated share.  The remaining pension and other postretirement net periodic benefit cost is allocated to other PHI subsidiaries.

(7)  DEBT

In March 2008, Pepco re-opened its November 2007 issue of $250 million 6.5% senior notes due November 2037 collateralized by first mortgage bonds, and issued an additional $250 million in principal amount of senior notes, increasing the outstanding principal amount of the 6.5% senior notes due November 2037 to $500 million. The net proceeds has been or will be used (a) to repay short-term debt, (b) to fund the retirement of $78 million of 6.5% first mortgage bonds on March 15, 2008, (c) to repay $50 million of 5.875% first mortgage bonds due October 15, 2008 at maturity, and (d) for general corporate purposes. In connection with the

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offering, Pepco agreed that for so long as the senior notes are outstanding they will remain secured by a corresponding series of first mortgage bonds.

In April 2008, Pepco purchased $109.5 million of Pollution Control Revenue Refunding Bonds Series 2006 due 2022 issued by the Maryland Economic Development Corporation. Although these bonds are considered to be extinguished for accounting purposes, Pepco intends to hold the bonds, while monitoring the market and evaluating the options for remarketing the bonds to the public.

In May 2008, Pepco completed two $25 million short-term bank loans, one maturing on September 30, 2008 and one on April 30, 2009.  Both are variable rate loans and Pepco has the option to repay the loans on any interest reset date without penalty.  Proceeds were used to temporarily finance the repurchase of Pepco insured tax exempt auction rate bonds.

(8)  INCOME TAXES

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

	For the Three Months Ended March 31,
	2008		2007
Federal statutory rate	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	5.1		10.4
Asset removal costs	(6.3)		(2.7)
State income taxes, net of federal effect	6.7		6.2
Software amortization	2.4		4.8
Tax credits	(2.0)		(3.4)
Change in estimates and interest related to uncertain and effectively settled tax positions	(2.7)		(5.5)
Permanent differences related to deferred compensation funding	2.0		-
Other, net	-		(4.8)
Effective Income Tax Rate	40.2	%	40.0	%

Pepco’s effective tax rates for the three months ended March 31, 2008 and 2007 were 40.2% and 40.0%, respectively.  The change in the rate resulted from an increase in asset removal costs offset by interest accrued on a tax claim filed with the IRS in March 2008.  The claim is for the treatment of casualty losses as current deductions (as opposed to being depreciated over their tax lives) on prior year returns currently under audit.

(9)  FAIR VALUE DISCLOSURES

Effective January 1, 2008, Pepco adopted SFAS No. 157 (as discussed herein in Note 3), which established a framework for measuring fair value and expands disclosures about fair value measurements.

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).  Pepco utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.  These inputs can be readily observable,

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market corroborated, or generally unobservable.  Accordingly, Pepco utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  Pepco is able to classify fair value balances based on the observability of those inputs.  SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).  The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

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

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

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources.  Level 3 includes those financial investments that are valued using models or other valuation methodologies.  Significant valuation inputs may have originated from internally developed methodologies that result in management’s best estimate of fair value.  Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs.  At each balance sheet date, Pepco performs an analysis of all instruments subject to SFAS No. 157 and includes in level 3 all of those whose fair value is based on significant unobservable inputs.

On February 12, 2008, the FASB issued FSP No. 157-2, “Effective Date of FASB Statement No. 157” (FSP No. 157-2), which defers the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually).  FSP No. 157-2 defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008.  Pepco liabilities that currently meet the deferral requirements of FSP No. 157-2 include Asset Retirement Obligations.

The following table sets forth by level within the fair value hierarchy the company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2008.  As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Pepco's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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	Fair Value Measurements at Reporting Date Using
	(Millions of dollars)
Description	March 31, 2008	Quoted Prices in Active Markets for Identical Instruments (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level  3)
ASSETS
Executive deferred   compensation plan assets	$57.8	$      -	$41.6	$16.2
	$57.8	$      -	$41.6	$16.2
LIABILITIES
Executive deferred   compensation plan liabilities	$26.6	$      -	$26.6	$     -
	$26.6	$      -	$26.6	$     -

A reconciliation of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (Level 3) is shown below (in millions of dollars):

	Deferred Compensation Plan Assets
Beginning balance as of January 1, 2008	$16.0
Total gains or (losses) (realized/unrealized)
Included in earnings (or changes in net assets)	.7
Included in other comprehensive income	-
Purchases, issuances and settlements	(.5)
Transfers in and/or out of Level 3	-
Ending balance as of March 31, 2008	$16.2
The amount of total gains for the period included in earnings (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at the reporting date.	$    .7
Gains or (losses) (realized and unrealized) included in earnings (or changes in net assets) for the period above are reported in Other Operation and Maintenance Expense as follows:
	Other Operation and Maintenance Expense
Total gains included in earnings (or changes in net assets) for the period above	$    .7
Change in unrealized gains relating to assets still held at reporting date	$    .7

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(10)  COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Proceeds from Settlement of Mirant Bankruptcy Claims

In 2000, Pepco sold substantially all of its electricity generating assets to Mirant and certain of its subsidiaries.  In 2003, Mirant commenced a voluntary bankruptcy proceeding in which it sought to reject certain obligations that it had undertaken in connection with the asset sale.  As part of the sale, Pepco and Mirant entered into a “back-to-back” arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco is obligated to purchase annually through 2021 from Panda under the Panda PPA at the purchase price Pepco is obligated to pay to Panda.  In connection with the settlement of Pepco’s claims against Mirant arising from the Mirant bankruptcy, Pepco agreed not to contest the rejection by Mirant of its obligations under the “back-to-back” arrangement in exchange for the payment by Mirant of damages corresponding to the estimated amount by which the purchase price that Pepco is obligated to pay Panda for the energy and capacity exceeded the market price.  In 2007, Pepco received as damages $413.9 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant.  These funds are being accounted for as restricted cash based on management’s intent to use such funds, and any interest earned thereon, for the sole purpose of paying for the future above-market capacity and energy purchase costs under the Panda PPA.  Correspondingly, a regulatory liability has been established in the same amount to help offset the future above-market capacity and energy purchase costs.  This restricted cash has been classified as a non-current asset to be consistent with the classification of the non-current regulatory liability, and any changes in the balance of this restricted cash, including interest on the invested funds, are being accounted for as operating cash flows.

As of March 31, 2008, the balance of the restricted cash account was $415.4 million.  Based on a reexamination of the costs of the Panda PPA in light of current and projected wholesale market conditions conducted in the fourth quarter of 2007, Pepco determined that, principally due to increases in wholesale capacity prices, the present valueabove-market cost of the Panda PPA over the term of the agreement is expected tobe significantly less than the current amount of the restricted cash account balance.  Accordingly, on February 22, 2008, Pepco filed applications with the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC) requesting orders directing Pepco to maintain $320 million in the restricted cash account and to use that cash, and any future earnings on the cash, for the sole purpose of paying the future above-market cost of the Panda PPA (or, in the alternative, to either fund a transfer or assignment of the remaining obligations under the Panda PPA to a third party or pay Panda to terminate the Panda PPA).  Pepco also requested that the order provide that any cash remaining in the account at the conclusion of the Panda PPA be refunded to customers and that any shortfall be recovered from customers.  Pepco further proposed that the excess proceeds remaining from the settlement (approximately $94.6 million, representing the amount by which the regulatory liability of $414.6 million at December 31, 2007 exceeded $320 million) be shared approximately equally with its customers in accordance with the procedures previously approved by each commission for the sharing of the proceeds received by Pepco from the sale to Mirant of its generating assets.  The amount of the restricted cash balance that Pepco is permitted to retain will be recorded as earnings upon approval of the sharing arrangement by the respective commissions.  At this time, Pepco cannot predict the outcome of these proceedings.

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Rate Proceedings

In electric service distribution base rate cases filed by Pepco in the District of Columbia and Maryland, Pepco proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers.  Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the approved revenue-per-customer amount.  The BSA will increase rates if actual distribution revenues fall below the level approved by the applicable commission and will decrease rates if actual distribution revenues are above the approved level.  The result will be that, over time, Pepco would 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.  The status of the BSA proposals in each of the jurisdictions is described below in the context of the respective base rate proceedings.

District of Columbia

In December 2006, Pepco submitted an application to the DCPSC to increase electric distribution base rates, including a proposed BSA.  On January 30, 2008, the DCPSC approved, effective February 20, 2008, a revenue requirement increase of approximately $28.3 million, based on an authorized return on rate base of 7.96%, including a 10% return on equity (ROE).  While finding the BSA to be an appropriate ratemaking concept, the DCPSC cited potential statutory problems in its authority to implement the BSA.  On February 28, 2008, the DCPSC established a Phase II proceeding to consider these implementation issues.  Initial briefs were filed on March 31, 2008; reply briefs were filed April 15, 2008.

Maryland

On July 19, 2007, the MPSC issued an order in the electric service distribution rate cases filed by Pepco, which included approval of a BSA.  The order approved an annual increase in distribution rates of approximately $10.6 million (including a decrease in annual depreciation expense of approximately $30.7 million).  The approved distribution rate reflects an ROE of 10.0%.  The rate increases were effective as of June 16, 2007, and remained in effect for an initial period until April 19, 2008.  On March 14, 2008, the MPSC extended this initial period to July 19, 2008.  These rates are subject to a Phase II proceeding in which the MPSC will consider the results of an audits of Pepco’s cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates is required.  Evidentiary hearings were held in mid-March 2008.  Initial briefs were filed on March 26, 2008 and reply briefs were filed April 7, 2008.

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Divestiture Cases

District of Columbia

In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets.  An unresolved issue relating to the application filed with the DCPSC by Pepco to implement the divestiture settlement is whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code and its implementing regulations.  As of March 31, 2008, 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 by Pepco, there is no book life over which the EDIT and ADITC can be returned.  If Pepco were required to share EDIT and ADITC and, as a result, the normalization rules were violated, Pepco would be unable to use accelerated depreciation on District of Columbia allocated or assigned property.  In addition to sharing with customers the generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS an amount equal to Pepco’s District of Columbia jurisdictional generation-related ADITC balance ($5.8 million as of March 31, 2008), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance $3.9 million as of March 31, 2008) 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.

On March 6, 2008, the IRS approved final regulations, effective March 20, 2008, which allow utilities whose assets cease to be utility property (whether by disposition, deregulation or otherwise) to return to its utility customers the normalization reserve for EDIT and part or all of the normalization reserve for ADITC.  This ruling applies to assets divested after December 21, 2005.  For utility property divested on or before December 21, 2005, the IRS stated that it would continue to follow the holdings set forth in private letter rulings prohibiting the flow through of EDIT and ADITC associated with the divested assets.  Pepco made a filing on April 22, 2008, advising the DCPSC of the adoption of the final regulations and requesting that the DCPSC issue an order consistent with the IRS position.  If the DCPSC issues the requested order, no accounting adjustments to the gain recorded in 2000 would be required.  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

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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 March 31, 2008, 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 (as discussed above) 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 March 31, 2008), 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 March 31, 2008), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($6.9 million as of March 31, 2008), 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.

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, pending completion of the IRS rulemaking regarding sharing of EDIT and ADITC related to divested assets.  Pepco made a filing on April 22, 2008, advising the MPSC of the adoption of the final IRS normalization regulations (described above under “Divestiture Cases -- District of Columbia”) and requesting that the MPSC issue a ruling on the appeal consistent with the IRS position.  If the MPSC issues the requested ruling, no accounting adjustments to the gain recorded in 2000 would be required.  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.

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

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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 March 31, 2008, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement between Pepco and Mirant under which Pepco sold its generation assets to Mirant in 2000.

While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) is approximately $360 million, PHI and Pepco believe the amounts claimed by 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.

Environmental Litigation

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

Carolina Transformer Site.  In August 2006, U.S. Environmental Protection Agency (EPA) notified Pepco that it had been identified as an entity that sent PCB-laden oil to be disposed at the Carolina Transformer site in Fayetteville, North Carolina.  The EPA notification stated that, on this basis, Pepco may be a potentially responsible party (PRP).  In December 2007, Pepco agreed to enter into a settlement agreement with EPA and the PRP group at the Carolina Transformer site.  In the first quarter 2008, the State of North Carolina indicated its intent to join in the settlement agreement as a party plaintiff.  Under the terms of the settlement, (i) Pepco paid $162,000 to resolve any liability that it might have at the site to EPA and the State of North Carolina, (ii) EPA and the State of North Carolina covenant not to sue or bring administrative action against Pepco for response costs at the site, (iii) other PRP group members

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release all rights for cost recovery or contribution claims they may have against Pepco, and (iv)  Pepco releases all rights for cost recovery or contribution claims that they may have against other parties settling with EPA and the State of North Carolina.  The consent decree is expected to be filed with the U.S. District Court in North Carolina in the second quarter of 2008.

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 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.

In 2005, the Treasury Department issued proposed 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 the proposed 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.

At the same time as the proposed 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 additional taxes and interest that management estimated to be payable for the years 2001 through 2004 based on the method of tax accounting that PHI, pursuant to the proposed regulations, 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.  It is reasonably possible that PHI’s unrecognized tax benefits related to this issue will significantly decrease in the next 12 months as a result of a settlement with the IRS.

(11)  RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including Pepco.  The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods.  These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI.  PHI Service Company costs

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directly charged or allocated to Pepco for the three months ended March 31, 2008 and 2007 were approximately $35.4 million and $31.2 million, respectively.

Certain subsidiaries of Pepco Energy Services perform utility maintenance services, including services that are treated as capital costs, for Pepco.  Amounts charged to Pepco by these companies for the three months ended March 31, 2008 and 2007 were approximately $2.7 million and $8.4 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 Three Months Ended March 31,
	2008	2007
Income (Expense)	(Millions of dollars)
Intercompany power purchases - Conectiv Energy Supply (a)	$(14.6)	$(15.9)
Intercompany lease transactions (b)	$   (.1)	$   (.3)

(a) Included in fuel and purchased energy.

(b) Included in other operation and maintenance.

As of March 31, 2008 and December 31, 2007, Pepco had the following balances on its Balance Sheets due (to)/from related parties:

	March 31, 2008	December 31, 2007
Asset (Liability)	(Millions of dollars)
Payable to Related Party (current)
PHI Service Company	$(16.3)	$(16.9)
Conectiv Energy Supply	(4.2)	(5.8)
Pepco Energy Services (a)	(47.7)	(53.0)
The items listed above are included in the “Accounts payable to associated companies” balance on the Balance Sheet of $68.2 million and $75.8 million at March 31, 2008 and December 31, 2007, respectively.
Money Pool Balance with Pepco Holdings (included in cash and   cash equivalents in 2008 and short-term debt in 2007)	$  43.6	$(95.9)
Money Pool Interest Accrued (included in interest accrued)	(.3)	(.3)

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

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DELMARVA POWER & LIGHT COMPANY STATEMENTS OF EARNINGS (Unaudited)
		Three Months Ended March 31,
			2008		2007
	(Millions of dollars)
Operating Revenue
Electric		$	294.8	$	308.7
Natural Gas			115.7		112.8
Total Operating Revenue			410.5		421.5
Operating Expenses
Fuel and purchased energy			195.4		220.8
Gas purchased			87.7		86.1
Other operation and maintenance			56.0		49.6
Depreciation and amortization			18.1		19.1
Other taxes			9.6		9.3
Gain on sale of assets			(3.1)		(.6)
Total Operating Expenses			363.7		384.3
Operating Income			46.8		37.2
Other Income (Expenses)
Interest and dividend income			1.1		.6
Interest expense			(9.5)		(11.0)
Other income			.7		.5
Other expenses			-		-
Total Other Expenses			(7.7)		(9.9)
Income Before Income Tax Expense			39.1		27.3
Income Tax Expense			13.0		11.3
Net Income			26.1		16.0
Retained Earnings at Beginning of Period			431.8		426.4
Dividends Paid to Parent			(27.0)		(8.0)
Preferred Stock Redemption			-		(.6)
Cumulative Effect Adjustment Related to the Implementation of FIN 48			-		.1
Retained Earnings at End of Period		$	430.9	$	433.9

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

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DELMARVA POWER & LIGHT COMPANY BALANCE SHEETS (Unaudited)
ASSETS		March 31, 2008		December 31, 2007
	(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$	31.4	$	11.4
Restricted cash			10.0		3.8
Accounts receivable, less allowance for uncollectible accounts     of $9.3 million and $8.0 million, respectively			197.0		194.9
Fuel, materials and supplies - at average cost			30.4		45.3
Prepayments of income taxes			33.4		56.1
Prepaid expenses and other			19.7		15.2
Total Current Assets			321.9		326.7
INVESTMENTS AND OTHER ASSETS
Goodwill			8.0		8.0
Regulatory assets			211.3		224.6
Prepaid pension expense			179.5		178.1
Other			49.1		35.3
Total Investments and Other Assets			447.9		446.0
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			2,563.8		2,615.8
Accumulated depreciation			(808.9)		(828.8)
Net Property, Plant and Equipment			1,754.9		1,787.0
TOTAL ASSETS		$	2,524.7	$	2,559.7

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

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DELMARVA POWER & LIGHT COMPANY BALANCE SHEETS (Unaudited)
LIABILITIES AND SHAREHOLDER’S EQUITY		March 31, 2008		December 31, 2007
	(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt		$	104.8	$	286.2
Current maturities of long-term debt			22.6		22.6
Accounts payable and accrued liabilities			92.2		104.7
Accounts payable to associated companies			38.6		54.0
Taxes accrued			16.0		8.2
Interest accrued			8.3		5.7
Liabilities and accrued interest related to uncertain tax positions			34.1		34.1
Other			62.6		60.5
Total Current Liabilities			379.2		576.0
DEFERRED CREDITS
Regulatory liabilities			276.0		275.5
Deferred income taxes, net			427.6		410.1
Investment tax credits			8.8		9.0
Above-market purchased energy contracts and other      electric restructuring liabilities			20.6		21.1
Other			56.1		65.2
Total Deferred Credits			789.1		780.9
LONG-TERM LIABILITIES
Long-term debt			621.6		529.4
COMMITMENTS AND CONTINGENCIES (NOTE 10)
SHAREHOLDER’S EQUITY
Common stock, $2.25 par value, authorized     1,000 shares, issued 1,000 shares			-		-
Premium on stock and other capital contributions			303.9		241.6
Retained earnings			430.9		431.8
Total Shareholder’s Equity			734.8		673.4
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY		$	2,524.7	$	2,559.7

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

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DELMARVA POWER & LIGHT COMPANY STATEMENTS OF CASH FLOWS (Unaudited)
	Three Months Ended March 31,
		2008		2007
	(Millions of dollars)
OPERATING ACTIVITIES
Net income	$	26.1	$	16.0
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		18.1		19.1
Gain on sale of assets		(3.1)		(.6)
Investment tax credit adjustments		(.2)		(.2)
Deferred income taxes		17.6		(.2)
Changes in:
Accounts receivable		(6.4)		(15.7)
Regulatory assets and liabilities		12.0		5.0
Accounts payable and accrued liabilities		(18.7)		32.2
Interest and taxes accrued		14.0		14.8
Other changes in working capital		13.6		14.9
Net other operating		(6.3)		(2.0)
Net Cash From Operating Activities		66.7		83.3
INVESTING ACTIVITIES
Net investment in property, plant and equipment		(32.0)		(26.6)
Restricted cash		(6.2)		(6.4)
Proceeds from sale of assets		50.1		-
Net other investing activities		.1		.3
Net Cash From (Used By) Investing Activities		12.0		(32.7)
FINANCING ACTIVITIES
Dividends paid to Parent		(27.0)		(8.0)
Capital contribution from Parent		62.3		-
Issuance of long-term debt		150.0		-
Reacquisitions of long-term debt		(57.8)		(11.5)
Reacquisitions of short-term debt, net		(181.4)		(12.7)
Redemption of preferred stock		-		(18.2)
Net other financing activities		(4.8)		(1.5)
Net Cash Used By Financing Activities		(58.7)		(51.9)
Net Increase (Decrease) in Cash and Cash Equivalents		20.0		(1.3)
Cash and Cash Equivalents at Beginning of Period		11.4		8.2
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	31.4	$	6.9
NONCASH ACTIVITIES
Asset retirement obligations associated with removal costs   transferred to regulatory liabilities	$	(5.4)	$	2.4
Cash paid for income taxes    (includes payments to PHI for Federal income taxes)	$	(16.3)	$	-

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 (until the sale of its Virginia operations on January 2, 2008), 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	Standard Offer Service (SOS)
Maryland	SOS
Virginia	Default Service (prior to January 2, 2008)

In this Form 10-Q, DPL also refers to these supply services 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).  On January 2, 2008, DPL completed (i) the sale of its retail electric distribution business on the Eastern Shore of Virginia to A&N Electric Cooperative (A&N) for a purchase price of approximately $48.8 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission business located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase price of approximately $5.4 million, after closing adjustments.  Each of A&N and ODEC assumed certain post-closing liabilities and unknown pre-closing liabilities related to the respective assets they are purchasing (including, in the A&N transaction, most environmental liabilities), except that DPL remained liable for unknown pre-closing liabilities if they become known within six months after the January 2, 2008 closing date.  These sales resulted in a $3.1 million pre-tax gain ($1.8 million after-tax), which was recorded during the first quarter of 2008.

(2)  SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

DPL’s unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP).  Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted.  Therefore, these financial statements should be read along with the annual financial statements included in DPL’s Annual Report on Form 10-K for the year ended December 31, 2007.  In the opinion of DPL’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly DPL’s financial condition as of March 31, 2008, in accordance with GAAP.  The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required

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by GAAP.  Interim results for the three months ended March 31, 2008 may not be indicative of results that will be realized for the full year ending December 31, 2008 since the sales of electric energy are seasonal.

Taxes Assessed by a Governmental Authority on Revenue-producing Transactions

Taxes included in DPL’s gross revenues were $3.5 million and $3.2 million for the three months ended March 31, 2008 and 2007, respectively.

Reclassifications

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

(3)  NEWLY ADOPTED ACCOUNTING STANDARDS

SFAS No. 157, "Fair Value Measurements"

In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (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.

SFAS No. 157 nullified a portion of Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,”(EITF 02-3).  Under EITF 02-3, the transaction price presumption prohibited recognition of a trading profit at inception of a derivative unless the positive fair value of that derivative was substantially based on quoted prices or a valuation process incorporating observable inputs.  For transactions that did not meet this criterion at inception, trading profits that had been deferred were recognized in the period that inputs to value the derivative became observable or when the contract performed.  SFAS No. 157 nullified this portion of EITF 02-3.  SFAS No. 157 also: (1) establishes that fair value is based on a hierarchy of inputs into the valuation process (as described in Note 9), (2) clarifies that an issuer's credit standing should be considered when measuring liabilities at fair value, (3) precludes the use of a liquidity or blockage factor discount when measuring instruments traded in an actively quoted market at fair value and (4) requires costs relating to acquiring instruments carried at fair value to be recognized as expense when incurred.  SFAS No. 157 requires that a fair value measurement reflect the assumptions market participants would use in pricing an asset or liability based on the best available information.  These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model.

The provisions of SFAS No. 157 are to be applied prospectively, except for the initial impact on three specific items: (1) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF 02-3, (2) existing hybrid financial instruments measured initially at fair value using the transaction price and (3) blockage factor discounts.  Adjustments to these items required under SFAS No. 157 are to be recorded as a transition adjustment to beginning retained earnings in the year of adoption.

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The provisions of SFAS No. 157, as issued, are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (January 1, 2008 for DPL).  On February 12, 2008, the FASB issued FASB Staff Position (FSP) No. 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” (FSP No. 157-1) that removes certain leasing transactions from the scope of SFAS No. 157.  On February 12, 2008, the FASB also issued FSP No. 157-2, “Effective Date of FASB Statement No. 157” (FSP No. 157-2) which defers the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually).  FSP No. 157-2 defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of the Final Staff Positions.

DPL applied the guidance of FSP No. 157-1 and FSP No. 157-2 with its adoption of SFAS No. 157 on January 1, 2008.  The adoption of SFAS No. 157 did not result in a transition adjustment to beginning retained earnings and did not have a material impact on DPL’s overall financial condition, results of operations or cash flows.  SFAS No. 157 also requires new disclosures regarding the level of pricing observability associated with financial instruments carried at fair value.  This additional disclosure is provided in Note 9, “Fair Value Disclosures,” herein.  Additionally, with the deferral of the effective date of SFAS No. 157 for certain non-financial assets and non-financial liabilities under FSP No. 157-2, DPL does not anticipate any material changes to 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 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 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 the beginning of a reporting entity’s first fiscal year that begins after November 15, 2007 (January 1, 2008 for DPL).  DPL adopted the provisions of SFAS No. 159 on January 1, 2008 and chose not to elect the fair value option for its eligible financial assets and liabilities.

FSP FIN 39-1, “Amendment of FASB Interpretation No. 39”

On April 30, 2007, the FASB issued FASB Interpretation Number (FIN) 39-1, “Amendment of FASB Interpretation No. 39,” to amend certain portions of Interpretation 39.  The FSP replaces the terms “conditional contracts” and “exchange contracts” in Interpretation 39 with the term “derivative instruments” as defined in Statement 133.  The FSP also amends Interpretation 39 to allow for the offsetting of fair value amounts for the right to reclaim cash collateral or receivable, or the obligation to return cash collateral or payable, arising from the same master netting arrangement as the derivative instruments. FSP FIN 39-1 applies to fiscal years beginning after November 15, 2007 (January 1, 2008 for DPL).

DPL retrospectively adopted the provisions of FSP FIN 39-1 and elected to offset fair value amounts recognized for derivative instruments and fair value amounts recognized for related collateral positions executed with the same counterparty under a master netting arrangement.  Additional disclosure of collateral positions that have been offset against net derivative positions is immaterial for disclosure.  The effect of retrospective application of FSP FIN 39-1 was not material at December 31, 2007 and, as such, no amounts were reclassified.

(4)  RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

SFAS No. 141(R), “Business Combinations – a replacement of FASB Statement No. 141”

On December 4, 2007, the FASB issued SFAS No. 141(R), “Business Combinations – a replacement of FASB Statement No. 141” (SFAS No. 141(R)) which replaces FASB Statement No. 141, “Business Combinations.”  This Statement retains the fundamental requirements in Statement 141 that the acquisition method of accounting (which Statement 141 called the purchase method) be used for all business combinations and for an acquirer to be identified for each business combination.

SFAS No. 141(R) applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree).  It does not apply to (i) the formation of a joint venture, (ii) the acquisition of an asset or a group of assets that does not constitute a business, (iii) a combination between entities or businesses under common control and (iv) a combination between not-for-profit organizations or the acquisition of a for-profit business by a not-for-profit organization.

This Statement amends FASB Statement No. 109, Accounting for Income Taxes, to require the acquirer to recognize changes in the amount of its deferred tax benefits that are recognizable because of a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances (such changes arise through the increase or reduction of the acquirer’s valuation allowance on its previously existing deferred tax assets because of the business combination).  Previously,

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Statement 109 required a reduction of the acquirer’s valuation allowance because of a business combination to be recognized through a corresponding reduction to goodwill.

SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for DPL).  An entity may not apply it before that date.  DPL is currently evaluating the impact SFAS No. 141(R) may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51”

On December 4, 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51” (SFAS No. 160), which amends ARB 51 to establish accounting and reporting standards for a noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary.  It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.

A noncontrolling interest, sometimes called a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. The objective of SFAS No. 160 is to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards that require (i) the ownership interests in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated statement of financial position within equity, but separate from the parent’s equity, (ii) the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of income, (iii) the changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently, and (iv) when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary must be initially measured at fair value.  The gain or loss on the deconsolidation of the subsidiary is measured using the fair value of any noncontrolling equity investment rather than the carrying amount of that retained investment and SFAS No. 160 requires that entities provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.

SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for DPL).  Earlier adoption is prohibited.  SFAS No. 160 shall be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, except for the presentation and disclosure requirements.  The presentation and disclosure requirements shall be applied retrospectively for all periods presented.  DPL is currently evaluating the impact SFAS No. 160 may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

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SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133”

On March 19, 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (SFAS No. 161) which changes the disclosure requirements for derivative instruments and hedging activities.  Entities will be required to provide enhanced disclosures about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows.

The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This disclosure is designed to better convey the purpose of derivative use in terms of the risks that the entity is intending to manage. Disclosing the fair values of derivative instruments and their gains and losses in a tabular format is intended to provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features should provide information on the potential effect on an entity’s liquidity from using derivatives.

SFAS No. 161 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after November 15, 2008 (January 1, 2009 for DPL).  Earlier adoption is encouraged.  SFAS No. 161 encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption.  DPL is currently evaluating the impact SFAS No. 161 may have on its footnote disclosure requirements.

(5) SEGMENT INFORMATION

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

(6)  PENSION AND OTHER POSTRETIREMENT BENEFITS

DPL accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan.  PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2008, of $16.0 million includes $.9 million for DPL’s allocated share.  The remaining pension and other postretirement net periodic benefit cost is allocated to other PHI subsidiaries.  PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2007, of $17.0 million includes $.3 million for DPL’s allocated share.  The remaining pension and other postretirement net periodic benefit cost is allocated to other PHI subsidiaries.

(7)  DEBT

In March 2008, DPL entered into a $150 million, unsecured two year bank loan agreement.  Interest on the loan is based on LIBOR plus an applicable margin, which varies according to DPL’s credit rating. The net proceeds were used to repay short-term debt.

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In March 2008, DPL purchased the following series of insured tax-exempt auction rate bonds that were issued by The Delaware Economic Development Authority for the benefit of DPL.  These purchases were made in response to disruption in the market for municipal auction rate securities that made it difficult for the remarketing agent to successfully remarket the bonds:

· $27.75 million of Exempt Facilities Revenue Refunding Bonds 2000B Series due 2030,

· $15 million of Exempt Facilities Revenue Refunding Bonds 2003A Series due 2038, and

· $15 million of Exempt Facilities Revenue Refunding Bonds 2002A Series due 2032.

Although these bonds are considered to be extinguished for accounting purposes, DPL intends to hold the bonds, while monitoring the market and evaluating the options for remarketing the bonds to the public.

For the reasons discussed above, in April 2008, DPL purchased the following additional series of insured tax-exempt auction rate bonds issued by the Delaware Economic Development Authority:

·   $20 million of Exempt Facilities Revenue Refunding Bonds 2001A Series due 2031,

·   $4.5 million of Exempt Facilities Revenue Refunding Bonds 2001B Series due 2031, and

·   $11.15 million of Exempt Facilities Revenue Refunding Bonds 2000A Series due 2030.

These bonds are also considered to be extinguished for accounting purposes, however, DPL intends to hold the bonds, while monitoring the market and evaluating the options for remarketing the bonds to the public.

(8)  INCOME TAXES

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

	For the Three Months Ended March 31,
	2008		2007
Federal statutory rate	35.0	%	35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect	5.4		5.1
Depreciation	1.5		1.8
Tax credits	(.5)		(.7)
Change in estimates and interest related to uncertain and effectively settled tax positions	(7.9)		.4
Other, net	(.3)		(.2)
Effective Income Tax Rate	33.2	%	41.4	%

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DPL’s effective tax rates for the three months ended March 31, 2008 and 2007 were 33.2% and 41.4%, respectively.  The decrease in the effective tax rate in 2008 was primarily related to interest accrued on a tax claim filed with the IRS in March 2008.  The claim is for the treatment of casualty losses as current deductions (as opposed to being depreciated over their tax lives) on prior year returns currently under audit.

(9)  FAIR VALUE DISCLOSURES

Effective January 1, 2008, DPL adopted SFAS No. 157 (as discussed herein in Note 3), which established a framework for measuring fair value and expands disclosures about fair value measurements.

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).  DPL utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.  These inputs can be readily observable, market corroborated, or generally unobservable.  Accordingly, DPL utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  DPL is able to classify fair value balances based on the observability of those inputs. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).  The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

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

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

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources.  Level 3 includes those financial investments that are valued using models or other valuation methodologies.  Significant valuation inputs may have originated from internally developed methodologies that result in management’s best estimate of fair value.  Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs.  At each balance sheet date, DPL performs an analysis of all instruments subject to SFAS No. 157 and includes in level 3 all of those whose fair value is based on significant unobservable inputs.

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On February 12, 2008, the FASB issued FSP No. 157-2, “Effective Date of FASB Statement No. 157” (FSP No. 157-2), which defers the effective date of SFAS No. 157 for all

non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually).  FSP No. 157-2 defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008.  DPL liabilities that currently meet the deferral requirements of FSP No. 157-2 include Asset Retirement Obligations.

The following table sets forth by level within the fair value hierarchy the company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2008.  As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  DPL's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at Reporting Date Using
	(Millions of dollars)
Description	March 31, 2008	Quoted Prices in Active Markets for Identical Instruments (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level  3)
ASSETS
Derivative Instruments	$4.2	$  -	$4.2	$   -
Executive deferred compensation plan assets	.8	-	-	.8
	$5.0	$  -	$4.2	$ .8
LIABILITIES
Derivative Instruments	$6.5	$  -	$ .1	$6.4
Executive deferred   compensation plan liabilities	.3	-	.3	-
	$6.8	$  -	$ .4	$6.4

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A reconciliation of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (Level 3) is shown below (in millions of dollars):

	Net Derivative Instruments	Deferred Compensation Plan Assets
Beginning balance as of January 1, 2008	$(10.7)	$  .8
Total gains or (losses) (realized/unrealized)
Included in earnings (or changes in net assets)	4.2	-
Included in other comprehensive income	-	-
Purchases, issuances and settlements	.1	-
Transfers in and/or out of Level 3	-	-
Ending balance as of March 31, 2008	$ (6.4)	$  .8
The amount of total gains for the period included in earnings (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at the reporting date.	$  3.6	$   -
Gains or (losses) (realized and unrealized) included in earnings (or changes in net assets) for the period above are reported in Operating Revenue and Other Operation and Maintenance Expense as follows:
	Operating Revenue	Other Operation and Maintenance Expense
Total gains included in earnings (or changes in net assets) for the period above	$4.2	$   -
Change in unrealized gains relating to assets still held at reporting date	$3.6	$   -

(10)  COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Rate Proceedings

In electric service distribution base rate cases filed by DPL in Maryland, DPL proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers.  Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the approved revenue-per-customer amount.  The BSA will increase rates if actual distribution revenues fall below the level approved by the Maryland Public Service Commission (MPSC) and will decrease rates if actual distribution revenues are above the approved level.  The result will be that, over time, DPL would 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 DPL to promote energy efficiency programs for its customers, because it breaks the link between overall sales volumes and delivery revenues.  The status of the BSA proposal is described below.

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On July 19, 2007, the MPSC issued orders in the electric service distribution rate case filed by DPL, which included approval of a BSA.  The order approved an annual increase in distribution rates of approximately $14.9 million (including a decrease in annual depreciation expense of approximately $.9 million).  The approved distribution rate reflects a return on equity of 10.0%.  The rate increases were effective as of June 16, 2007, and remained in effect for an initial period until April 19, 2008.  On March 14, 2008, the MPSC extended this initial period to July 19, 2008.  These rates are subject to a Phase II proceeding in which the MPSC will consider the results of an audit of DPL’s cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates is required.  Evidentiary hearings were held in mid-March 2008.  Initial briefs were filed on March 26, 2008 and reply briefs were filed April 7, 2008.

Sale of Virginia Operations

On January 2, 2008, DPL completed (i) the sale of its retail electric distribution business on the Eastern Shore of Virginia to A&N for a purchase price of approximately $48.8 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission business located on the Eastern Shore of Virginia to ODEC for a purchase price of approximately $5.4 million, after closing adjustments.  Each of A&N and ODEC assumed certain post-closing liabilities and unknown pre-closing liabilities related to the respective assets they purchased (including, in the A&N transaction, most environmental liabilities), except that DPL remained liable for unknown pre-closing liabilities if they become known within six months after the January 2, 2008 closing date.  These sales resulted in a $3.1 million pre-tax gain ($1.8 million after-tax), which was recorded in the first quarter of 2008.  In accordance with the purchase and sale agreements, the final closing adjustments will be recorded in the second quarter of 2008.

Environmental Litigation

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

Carolina Transformer Site.  In August 2006, U.S. Environmental Protection Agency (EPA) notified DPL that it had been identified as an entity that sent PCB-laden oil to be disposed at the Carolina Transformer site in Fayetteville, North Carolina.  The EPA notification stated that, on this basis, DPL may be a potentially responsible party (PRP).  In December 2007, DPL agreed to enter into a settlement agreement with EPA and the PRP group at the Carolina Transformer site.  In the first quarter 2008, the State of North Carolina indicated its intent to join in the settlement agreement as a party plaintiff.  Under the terms of the settlement, (i)  DPL paid $162,000 to resolve any liability that it might have at the site to EPA and the State of North Carolina, (ii) EPA and the State of North Carolina covenant not to sue or bring administrative action against DPL for response costs at the site, (iii) other PRP group members release all rights

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for cost recovery or contribution claims they may have against DPL, and (iv) DPL releases all rights for cost recovery or contribution claims that they may have against other parties settling with EPA and the State of North Carolina.  The consent decree is expected to be filed with the U.S. District Court in North Carolina in the second quarter of 2008.

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.

In 2005, the Treasury Department issued proposed 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 tax periods beginning in 2005.  Based on the proposed 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).

At the same time as the proposed 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 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 additional taxes and interest that management estimated to be payable for the years 2001 through 2004 based on the method of tax accounting that PHI, pursuant to the proposed regulations, 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.  It is reasonably possible that PHI’s unrecognized tax benefits related to this issue will significantly decrease in the next 12 months as a result of a settlement with the IRS.

(11)  RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including DPL.  The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods.  These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI.  PHI Service Company costs directly charged or allocated to DPL for the three months ended March 31, 2008 and 2007 were $27.5 million and $26.2 million, respectively.

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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 Three Months Ended March 31,
	2008	2007
Income (Expense)	(Millions of dollars)
SOS with Conectiv Energy Supply (a)	$(61.4)	$(76.3)
Intercompany lease transactions (b)	1.7	1.9
Transcompany pipeline gas purchases with Conectiv Energy Supply (c)	(.3)	(1.3)
Transcompany pipeline gas sales with Conectiv Energy Supply (d)	.1	1.5

(a) Included in fuel and purchased energy.

(b) Included in electric revenue.

(c) Included in gas purchased.

(d) Included in gas revenue.

As of March 31, 2008 and December 31, 2007, DPL had the following balances on its Balance Sheets due (to)/from related parties:

	March 31, 2008		December 31, 2007
Asset (Liability)		(Millions of dollars)
Payable to Related Party (current)
PHI Service Company	$	(15.1)	$	(24.7)
Conectiv Energy Supply		(19.1)		(23.0)
Pepco Energy Services		(5.2)		(6.6)
The items listed above are included in the “Accounts payable to associated companies” balance on the   Balance Sheet of $38.6 million and $54.0 million at March 31, 2008 and December 31, 2007, respectively.
Money Pool Balance with Pepco Holdings (included in cash and   cash equivalents in 2008 and short-term debt in 2007)	$	20.7	$	(157.4)
Money Pool Interest Accrued (included in interest accrued)	$	(.1)	$	(.6)

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF EARNINGS (Unaudited)
		Three Months Ended March 31,
			2008		2007
	(Millions of dollars)
Operating Revenue		$	361.5	$	338.2
Operating Expenses
Fuel and purchased energy			245.3		223.8
Other operation and maintenance			46.1		39.6
Depreciation and amortization			24.1		17.1
Other taxes			5.9		5.7
Deferred electric service costs			24.7		26.0
Gain on sale of assets			-		(.3)
Total Operating Expenses			346.1		311.9
Operating Income			15.4		26.3
Other Income (Expenses)
Interest and dividend income			.5		.5
Interest expense			(14.8)		(16.0)
Other income			1.1		1.2
Other expenses			(.4)		-
Total Other Expenses			(13.6)		(14.3)
Income Before Income Tax (Benefit) Expense			1.8		12.0
Income Tax (Benefit) Expense			(3.5)		4.3
Income from Continuing Operations			5.3		7.7
Discontinued Operations (Note 12)
Income from operations (net of taxes of zero and $.1 million, respectively)			-		.1
Net Income			5.3		7.8
Dividends on Redeemable Serial Preferred Stock			.1		.1
Earnings Available for Common Stock			5.2		7.7
Retained Earnings at Beginning of Period			141.8		132.0
Dividends Paid to Parent			-		(20.0)
Retained Earnings at End of Period		$	147.0	$	119.7

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

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)
ASSETS		March 31, 2008		December 31, 2007
	(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$	10.9	$	7.0
Restricted cash			9.4		9.5
Accounts receivable, less allowance for uncollectible accounts     of $5.5 million and $4.9 million, respectively			177.9		198.1
Fuel, materials and supplies - at average cost			14.9		14.1
Prepayments of income taxes			46.8		47.0
Prepaid expenses and other			17.1		16.8
Total Current Assets			277.0		292.5
INVESTMENTS AND OTHER ASSETS
Regulatory assets			807.1		818.0
Restricted funds held by trustee			5.6		6.8
Prepaid pension expense			7.7		8.5
Other			66.5		36.9
Total Investments and Other Assets			886.9		870.2
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			2,125.5		2,078.0
Accumulated depreciation			(640.5)		(633.5)
Net Property, Plant and Equipment			1,485.0		1,444.5
TOTAL ASSETS		$	2,648.9	$	2,607.2

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

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)
LIABILITIES AND SHAREHOLDER’S EQUITY		March 31, 2008		December 31, 2007
	(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt		$	57.6	$	51.7
Current maturities of long-term debt			66.1		81.0
Accounts payable and accrued liabilities			115.6		128.9
Accounts payable to associated companies			23.0		18.3
Taxes accrued			24.9		30.2
Interest accrued			11.3		13.3
Liabilities and accrued interest related to uncertain tax positions			26.6		26.6
Other			34.1		37.0
Total Current Liabilities			359.2		387.0
DEFERRED CREDITS
Regulatory liabilities			455.4		430.9
Deferred income taxes, net			416.0		386.3
Investment tax credits			10.8		11.1
Other postretirement benefit obligation			38.8		38.0
Other			28.6		21.2
Total Deferred Credits			949.6		887.5
LONG-TERM LIABILITIES
Long-term debt			390.7		415.7
Transition Bonds issued by ACE Funding			425.7		433.5
Total Long-Term Liabilities			816.4		849.2
COMMITMENTS AND CONTINGENCIES (NOTE 10)
REDEEMABLE SERIAL PREFERRED STOCK			6.2		6.2
SHAREHOLDER’S EQUITY
Common stock, $3.00 par value, authorized     25,000,000 shares, and 8,546,017 shares outstanding			25.6		25.6
Premium on stock and other capital contributions			344.9		309.9
Retained earnings			147.0		141.8
Total Shareholder’s Equity			517.5		477.3
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY		$	2,648.9	$	2,607.2

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

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
		Three Months Ended March 31,
			2008		2007
	(Millions of dollars)
OPERATING ACTIVITIES
Net income		$	5.3	$	7.8
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization			24.1		17.1
Deferred income taxes			27.8		23.6
Gain on sale of assets			-		(.3)
Changes in:
Accounts receivable			20.2		.8
Accounts payable and accrued liabilities			(2.9)		(15.7)
Regulatory assets and liabilities			26.2		21.7
Interest and taxes accrued			(35.4)		(14.6)
Other changes in working capital			-		(1.5)
Net other operating			7.1		(10.0)
Net Cash From Operating Activities			72.4		28.9
INVESTING ACTIVITIES
Net investment in property, plant and equipment			(57.0)		(23.9)
Proceeds from sale of assets			.5		9.0
Net other investing activities			1.2		1.2
Net Cash Used By Investing Activities			(55.3)		(13.7)
FINANCING ACTIVITIES
Dividends paid to Parent			-		(20.0)
Dividends paid on preferred stock			(.1)		(.1)
Capital contribution from Parent			35.0		-
Reacquisition of long-term debt			(47.6)		(7.3)
Issuances of short-term debt, net			5.9		12.5
Net other financing activities			(6.4)		(.6)
Net Cash Used By Financing Activities			(13.2)		(15.5)
Net Increase (Decrease) in Cash and Cash Equivalents			3.9		(.3)
Cash and Cash Equivalents at Beginning of Period			7.0		5.5
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	10.9	$	5.2
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid (received) for income taxes    (includes payments to PHI for Federal income taxes)		$	7.6	$	(.2)

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ATLANTIC CITY ELECTRIC COMPANY

(1) ORGANIZATION

Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey.  ACE provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive supplier.  Default Electricity Supply is also known as Basic Generation Service (BGS).  ACE is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).

In addition to its electricity transmission and distribution operations, during 2007 ACE owned the B.L. England electric generating facility (with a generating capacity of 447 megawatts).  On February 8, 2007, ACE completed the sale of the B.L. England generating facility.

(2)  SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

ACE’s unaudited consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP).  Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted.  Therefore, these financial statements should be read along with the annual financial statements included in ACE’s Annual Report on Form 10-K for the year ended December 31, 2007.  In the opinion of ACE’s management, the consolidated financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly ACE’s financial condition as of March 31, 2008, in accordance with GAAP.  The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.  Interim results for the three months ended March 31, 2008 may not be indicative of results that will be realized for the full year ending December 31, 2008 since the sales of electric energy are seasonal.

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 Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R (revised December 2003), entitled “Consolidation of Variable Interest Entities” (FIN 46R) and FASB Staff Position (FSP) FIN 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)” (FSP FIN 46(R)-6), ACE continued, during the first quarter of 2008, 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

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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 three months ended March 31, 2008 and 2007 were approximately $88 million and $82 million, respectively, of which approximately $76 million and $73 million, respectively, related to power purchases under the NUGs.  ACE does not have exposure to loss under the NUGs because cost recovery will be achieved from its customers through regulated rates.

Taxes Assessed by a Governmental Authority on Revenue-producing Transactions

Taxes included in ACE’s gross revenues were $5.4 million and $5.5 million for the three months ended March 31, 2008 and 2007, respectively.

(3)  NEWLY ADOPTED ACCOUNTING STANDARDS

SFAS No. 157, "Fair Value Measurements"

In September 2006, the FASB issued Statement of Financial Accounting Standards (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.

SFAS No. 157 nullified a portion of Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,”(EITF 02-3).  Under EITF 02-3, the transaction price presumption prohibited recognition of a trading profit at inception of a derivative unless the positive fair value of that derivative was substantially based on quoted prices or a valuation process incorporating observable inputs.  For transactions that did not meet this criterion at inception, trading profits that had been deferred were recognized in the period that inputs to value the derivative became observable or when the contract performed.  SFAS No. 157 nullified this portion of EITF 02-3.  SFAS No. 157 also: (1) establishes that fair value is based on a hierarchy of inputs into the valuation process (as described in Note 9), (2) clarifies that an issuer's credit standing should be considered when measuring liabilities at fair value, (3) precludes the use of a liquidity or blockage factor discount when measuring instruments traded in an actively quoted market at fair value and (4) requires costs relating to acquiring instruments carried at fair value to be recognized as expense when incurred.  SFAS No. 157 requires that a fair value measurement reflect the assumptions market participants would use in pricing an asset or liability based on the best available information.  These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model.

The provisions of SFAS No. 157 are to be applied prospectively, except for the initial impact on three specific items: (1) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF 02-3, (2) existing hybrid financial instruments measured initially at fair value using the transaction price

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and (3) blockage factor discounts.  Adjustments to these items required under SFAS No. 157 are to be recorded as a transition adjustment to beginning retained earnings in the year of adoption.

The provisions of SFAS No. 157, as issued, are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (January 1, 2008 for ACE).  On February 12, 2008, the FASB issued FSP No. 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” (FSP No. 157-1) that removes certain leasing transactions from the scope of SFAS No. 157.  On February 12, 2008, the FASB also issued FSP No. 157-2, “Effective Date of FASB Statement No. 157” (FSP No. 157-2) which defers the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually).  FSP No. 157-2 defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of the Final Staff Positions.

ACE applied the guidance of FSP No. 157-1 and FSP No. 157-2 with its adoption of SFAS No. 157 on January 1, 2008.  The adoption of SFAS No. 157 did not result in a transition adjustment to beginning retained earnings and did not have a material impact on ACE’s overall financial condition, results of operations or cash flows.  SFAS No. 157 also requires new disclosures regarding the level of pricing observability associated with financial instruments carried at fair value.  This additional disclosure is provided in Note 9, “Fair Value Disclosures,” herein.  Additionally, with the deferral of the effective date of SFAS No. 157 for certain non-financial assets and non-financial liabilities under FSP No. 157-2, ACE does not anticipate any material changes to 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 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 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

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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 the beginning of a reporting entity’s first fiscal year that begins after November 15, 2007 (January 1, 2008 for ACE).  ACE adopted the provisions of SFAS No. 159 on January 1, 2008 and chose not to elect the fair value option for its eligible financial assets and liabilities.

(4)  RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

SFAS No. 141(R), “Business Combinations – a replacement of FASB Statement No. 141”

On December 4, 2007, the FASB issued SFAS No. 141(R), “Business Combinations – a replacement of FASB Statement No. 141” (SFAS No. 141(R)) which replaces FASB Statement No. 141, “Business Combinations.”  This Statement retains the fundamental requirements in Statement 141 that the acquisition method of accounting (which Statement 141 called the purchase method) be used for all business combinations and for an acquirer to be identified for each business combination.

SFAS No. 141(R) applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree).  It does not apply to (i) the formation of a joint venture, (ii) the acquisition of an asset or a group of assets that does not constitute a business, (iii) a combination between entities or businesses under common control and (iv) a combination between not-for-profit organizations or the acquisition of a for-profit business by a not-for-profit organization.

This Statement amends FASB Statement No. 109, Accounting for Income Taxes, to require the acquirer to recognize changes in the amount of its deferred tax benefits that are recognizable because of a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances (such changes arise through the increase or reduction of the acquirer’s valuation allowance on its previously existing deferred tax assets because of the business combination).  Previously, Statement 109 required a reduction of the acquirer’s valuation allowance because of a business combination to be recognized through a corresponding reduction to goodwill.

SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for ACE).  An entity may not apply it before that date.  ACE is currently evaluating the impact SFAS No. 141(R) may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51”

On December 4, 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51” (SFAS No. 160), which amends ARB 51 to establish accounting and reporting standards for a noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary.  It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.

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A noncontrolling interest, sometimes called a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. The objective of SFAS No. 160 is to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards that require (i) the ownership interests in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated statement of financial position within equity, but separate from the parent’s equity, (ii) the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of income, (iii) the changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently, and (iv) when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary must be initially measured at fair value.  The gain or loss on the deconsolidation of the subsidiary is measured using the fair value of any noncontrolling equity investment rather than the carrying amount of that retained investment and SFAS No. 160 requires that entities provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.

SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for ACE).  Earlier adoption is prohibited.  SFAS No. 160 shall be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, except for the presentation and disclosure requirements.  The presentation and disclosure requirements shall be applied retrospectively for all periods presented.  ACE is currently evaluating the impact SFAS No. 160 may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

(5) SEGMENT INFORMATION

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

(6)  PENSION AND OTHER POSTRETIREMENT BENEFITS

ACE accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan.  PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2008, of $16.0 million includes $3.3 million for ACE’s allocated share.  The remaining pension and other postretirement net periodic benefit cost is allocated to other PHI subsidiaries.  PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2007, of $17.0 million includes $3.5 million for ACE’s allocated share.  The remaining pension and other postretirement net periodic benefit cost is allocated to other PHI subsidiaries.

(7)  DEBT

In January 2008, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $5.4 million on Series 2002-1 Bonds, Class A-1 and $2.2 million on Series 2003-1.

In March 2008, ACE retired at maturity $15 million of medium-term notes with a weighted average interest rate of 6.79%.

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In March 2008, ACE purchased $25 million of Pollution Control Revenue Refunding Bonds 2004A Series due 2029, issued by Cape May County.  This series of insured tax-exempt auction rate bonds was purchased in response to a disruption in the market for municipal auction rate securities that made it difficult for the remarketing agent to successfully remarket the bonds.  Although these bonds are considered to be extinguished for accounting purposes, ACE intends to hold the bonds, while monitoring the market and evaluating the options for remarketing the bonds to the public.

For the reasons discussed above, in April 2008, ACE purchased the following additional series of insured tax-exempt auction rate bonds:

·   $23.15 million of Pollution Control Revenue Refunding Bonds Series 2004A due 2029 issued by Salem County and

·   $6.5 million of Pollution Control Revenue Refunding Bonds Series 2004B due 2029 issued by Cape May County.

These bonds are also considered to be extinguished for accounting purposes, however, ACE intends to hold the bonds, while monitoring the market and evaluating the options for remarketing the bonds to the public.

(8)  INCOME TAXES

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

	For the Three Months Ended March 31,
	2008		2007
Federal statutory rate	35.0	%	35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect	16.7		5.8
Depreciation	(11.1)		.8
Tax credits	(16.7)		(2.5)
Adjustment to prior years’ tax	-		(.8)
Change in estimates and interest related to uncertain and effectively settled tax positions	(205.6)		(1.7)
AFUDC - Equity	(5.6)		(.7)
Service company cost allocation	(5.6)		-
Government subsidy related to OPEB benefits	(5.6)		-
Other, net	4.1		(.1)
Consolidated Effective Income Tax Rate	(194.4)	%	35.8	%

ACE’s effective tax rates for the three months ended March 31, 2008 and 2007 were (194.4)% and 35.8%, respectively.  The decrease in the effective tax rate in 2008 was primarily the result of depreciation method differences and interest accrued on a tax claim filed with the IRS in March 2008.  The claim is for the treatment of casualty losses as current deductions (as opposed to being depreciated over their tax lives) on prior year returns currently under audit.

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(9)  FAIR VALUE DISCLOSURES

Effective January 1, 2008, ACE adopted SFAS No. 157 (as discussed herein in Note 3), which established a framework for measuring fair value and expands disclosures about fair value measurements.

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).  ACE utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.  These inputs can be readily observable, market corroborated, or generally unobservable.  Accordingly, ACE utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  ACE is able to classify fair value balances based on the observability of those inputs. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).  The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

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

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

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources.  Level 3 includes those financial investments that are valued using models or other valuation methodologies.  Significant valuation inputs may have originated from internally developed methodologies that result in management’s best estimate of fair value.  Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs.  At each balance sheet date, ACE performs an analysis of all instruments subject to SFAS No. 157 and includes in level 3 all of those whose fair value is based on significant unobservable inputs.

On February 12, 2008, the FASB issued FSP No. 157-2, “Effective Date of FASB Statement No. 157” (FSP No. 157-2), which defers the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually).  FSP No. 157-2 defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008.  ACE liabilities that currently meet the deferral requirements of FSP No. 157-2 include Asset Retirement Obligations.

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

	Fair Value Measurements at Reporting Date Using
	(Millions of dollars)
Description	March 31, 2008	Quoted Prices in Active Markets for Identical Instruments (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level  3)
ASSETS
Executive deferred compensation plan assets	$.3	$-	$-	$.3
	$.3	$-	$-	$.3
LIABILITIES
Executive deferred   compensation plan liabilities	$.8	$-	$.8	$-
	$.8	$-	$.8	$-

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A reconciliation of the beginning and ending balances of ACE’s fair value measurements using significant unobservable inputs (Level 3) is shown below (in millions of dollars):

	Deferred Compensation Plan Assets
Beginning balance as of January 1, 2008	$  .3
Total gains or (losses) (realized/unrealized)
Included in earnings (or changes in net assets)	-
Included in other comprehensive income	-
Purchases, issuances and settlements	-
Transfers in and/or out of Level 3	-
Ending balance as of March 31, 2008	$  .3
The amount of total gains for the period included in earnings (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at the reporting date.	$    -
Gains or (losses) (realized and unrealized) included in earnings (or changes in net assets) for the period above are reported in Other Operation and Maintenance Expense as follows:
	Other Operation and Maintenance Expense
Total gains included in earnings (or changes in net assets) for the period above	$    -
Change in unrealized gains relating to assets still held at reporting date	$    -

(10)  COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Rate Proceedings

On June 1, 2007, ACE filed with the New Jersey Board of Public Utilities (NJBPU) an application for permission to decrease the Non Utility Generation Charge (NGC) and increase components of its Societal Benefits Charge (SBC) to be collected from customers for the period October 1, 2007 through September 30, 2008.  The proposed changes are designed to effect a true-up of the actual and estimated costs and revenues collected through the current NGC and SBC rates through September 30, 2007 and, in the case of the SBC, forecasted costs and revenues for the period October 1, 2007 through September 30, 2008.

As of March 31, 2008, the NGC, which is intended primarily to recover the above-market component of payments made by ACE under non-utility generation contracts and stranded costs associated with those commitments, had an over-recovery balance of $247.5 million.  The filing proposed that the estimated NGC balance as of September 30, 2007 in the amount of $216.2 million, including interest, be amortized and returned to ACE customers over a four-year period, beginning October 1, 2007.

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As of March 31, 2008, the SBC, which is intended to allow ACE to recover certain costs involved with various NJBPU-mandated social programs, had an under-recovery of approximately $24.3 million, primarily due to increased costs associated with funding the New Jersey Clean Energy Program.  In addition, ACE has requested an increase to the SBC to reflect the funding levels approved by the NJBPU of $20.4 million for the period October 1, 2007 through September 30, 2008, bringing to $40 million the total recovery requested for the period October 1, 2007 to September 30, 2008 (based upon actual data through August 2007).

The net impact of the proposed adjustments to the NGC and the SBC, including associated changes in sales and use tax, is an overall distribution rate decrease of approximately $117.3 million as of March 31, 2009, for the period June 1, 2008 through May 31, 2009 (the final rate changes will be based upon actual data through March 2008).  A Stipulation of Settlement (the Stipulation) memorializing the terms of a negotiated resolution has been executed by NJBPU staff, the New Jersey Division of Rate Counsel and ACE.  The Stipulation reflects negotiated adjustments that reduce the amount ACE will recover from customers by approximately $1.1 million as part of a compromise offer, and the associated rate decrease shown above.  The Stipulation is subject to the approval of the NJBPU.  On May 1, 2008, the administrative law judge in the proceeding recommended that the NJBPU approve the Stipulation, which is scheduled for NJBPU consideration on May 8, 2008.  If the Stipulation is approved by the NJBPU and implemented, ACE anticipates that the revised rates will remain in effect until May 31, 2009, subject to an annual true-up and change each year thereafter.

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 elect to purchase electricity from a competitive 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

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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 $195.0 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 2005, an additional $1.2 million in interest on the disallowed amount was identified and reserved by ACE.  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.  On August 9, 2007, the Appellate Division, citing deference to the factual and policy findings of the NJBPU, affirmed the NJBPU’s decision in its entirety, rejecting challenges from ACE and the Division of Rate Counsel.  On September 10, 2007, ACE filed an application for certification to the New Jersey Supreme Court.  On January 15, 2008, the New Jersey Supreme Court denied ACE’s application for certification.  Because the full amount at issue in this proceeding was previously reserved by ACE, there will be no further financial statement impact to ACE.

ACE Sale of B.L. England Generating Facility

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 which it received proceeds of approximately $9 million.  At the time of the sale, RC Cape May and ACE agreed to submit to arbitration the issue of whether RC Cape May, under the terms of the purchase agreement, must pay to ACE an additional $3.1 million as part of the purchase price.  On February 26, 2008, the arbitrators issued a decision awarding $3.1 million to ACE, plus interest, attorneys’ fees and costs, for a total award of approximately $4.2 million.

On July 18, 2007, ACE received a claim for indemnification from RC Cape May under the purchase agreement.  RC Cape May contends that one of the assets it purchased, a contract for terminal services (TSA) between ACE and Citgo Asphalt Refining Co. (Citgo), has been declared by Citgo to have been terminated due to a failure by ACE to renew the contract in a timely manner.  RC Cape May has commenced an arbitration proceeding against Citgo seeking a determination that the TSA remains in effect and has notified ACE of the proceeding.  In addition, RC Cape May has asserted a claim for indemnification from ACE in the amount of $25 million if the TSA is held not to be enforceable against Citgo.  While ACE believes that it has defenses to the indemnification claims, should the arbitrator rule that the TSA has terminated, the outcome of this matter is uncertain.  ACE notified RC Cape May of its intent to participate in the pending arbitration.

The sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized.  In accordance with an NJBPU order dated April 16, 2008, the net proceeds from the sale of the plant and monetization of the emission allowance credits, estimated to be $39.9 million as of May 31, 2008, will be credited to ACE’s customers, over a period of approximately12 monthsbeginning on June 1, 2008.

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Environmental Litigation

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

Delilah Road Landfill Site.  In 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 administrative consent order with NJDEP to remediate the site.  The soil cap remedy for the site has been implemented and in August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site.  Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years.  In September 2007, NJDEP approved the PRP group’s petition to conduct semi-annual, rather than quarterly, ground water monitoring for two years and deferred until the end of the two-year period a decision on the PRP group’s request for annual groundwater monitoring thereafter.  In August 2007, the PRP group agreed to reimburse the U.S. Environmental Protection Agency’s (EPA’s) costs in the amount of $81,400 in full satisfaction of EPA’s claims for all past and future response costs relating to the site (of which ACE’s share is one-third) and in October 2007, EPA and the PRP group entered into a tolling agreement to permit the parties sufficient time to execute a final settlement agreement.  This settlement agreement, with an April 11, 2008 effective date, will allow EPA to reopen the settlement in the event of new information or unknown conditions at the site.  Based on information currently available, ACE anticipates that its share of additional cost associated with this site for post-remedy operation and maintenance will be approximately $555,000 to $600,000.  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.

Frontier Chemical Site.  On June 29, 2007, ACE received a letter from the New York Department of Environmental Conservation (NYDEC) identifying ACE as a PRP at the Frontier Chemical Waste Processing Company site in Niagara Falls, N.Y. based on hazardous waste manifests indicating that ACE sent in excess of 7,500 gallons of manifested hazardous waste to the site.  ACE has entered into an agreement with the other parties identified as PRPs to form the PRP group and has informed NYDEC that it has entered into good faith negotiations with the PRP group to address ACE’s responsibility at the site.  ACE believes that its responsibility at the site will not have a material adverse effect on its financial position, results of operations or cash flows.

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IRS Mixed Service Cost Issue

During 2001, ACE changed its method of accounting with respect to capitalizable construction costs for income tax purposes.  The change allowed 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.

In 2005, the Treasury Department issued proposed regulations that, if adopted in their current form, would require ACE to change its method of accounting with respect to capitalizable construction costs for income tax purposes for tax periods beginning in 2005.  Based on the proposed 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).

At the same time as the proposed 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 additional taxes and interest that management estimated to be payable for the years 2001 through 2004 based on the method of tax accounting that PHI, pursuant to the proposed regulations, 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.  It is reasonably possible that PHI’s unrecognized tax benefits related to this issue will significantly decrease in the next 12 months as a result of a settlement with the IRS.

(11) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including ACE.  The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods.  These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI.  PHI Service Company costs directly charged or allocated to ACE for the three months ended March 31, 2008 and 2007 were $21.6 million and $20.1 million, respectively.

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

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	For the Three Months Ended March 31,
	2008	2007
Income (Expense)	(Millions of dollars)
Purchased power from Conectiv Energy Supply (a)	$(21.9)	$(18.9)
Meter reading services provided by Millennium Account Services LLC (b)	(1.0)	(1.0)
Intercompany use revenue (c)	.5	.6
Intercompany use expense (c)	(.5)	(.6)

     (a) Included in fuel and purchased energy.

     (b) Included in other operation and maintenance.

     (c) Included in operating revenue.

     As of March 31, 2008 and December 31, 2007, ACE had the following balances on its Consolidated Balance Sheets due (to)/from related parties:

		March 31, 2008	December 31, 2007
Asset (Liability)		(Millions of dollars)
Payable to Related Party (current)
PHI Service Company	$	(10.1)	$	(10.4)
Conectiv Energy Supply		(12.1)		(7.8)
The items listed above are included in the “Accounts payable to associated companies” balance on   the Consolidated Balance Sheet of $23.0 million and $18.3 million at March 31, 2008 and   December 31, 2007, respectively.

(12)  DISCONTINUED OPERATIONS

As discussed in Note (10) “Commitments and Contingencies,” herein, on February 8, 2007, ACE completed the sale of the B.L. England generating facility.  B.L. England comprised a significant component of ACE’s generation operations and its sale required discontinued operations presentation under SFAS No. 144, “Accounting for the Impairment or Disposal of Long Lived Assets,” on ACE’s Consolidated Statement of Earnings for the three months ended March 31, 2007.

The following table summarizes discontinued operations information for the three months ended March 31, 2007 (millions of dollars):

	2007
Operating Revenue	$	9.7
Income Before Income Tax Expense	$	.2
Net Income	$	.1

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

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

Registrants	Page No.
Pepco Holdings	99
Pepco	126
DPL	134
ACE	143

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

  AND RESULTS OF OPERATIONS

PEPCO HOLDINGS, INC.

GENERAL OVERVIEW

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

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

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

For the three months ended March 31, 2008 and 2007, respectively, PHI’s Power Delivery operations produced 49% and 59% of PHI’s consolidated operating revenues (including revenues from intercompany transactions) and 47% and 62% of PHI’s consolidated operating income (including income from intercompany transactions).

For the three months ended March 31, 2008 and 2007, the distribution, transmission and default supply of electric power accounted for 91% of Power Delivery’s operating revenues and the delivery and supply of natural gas contributed 9% of Power Delivery’s operating revenues.  Power Delivery represents one operating segment for financial reporting purposes.

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

Delaware	Standard Offer Service (SOS)
District of Columbia	SOS
Maryland	SOS
New Jersey	Basic Generation Service
Virginia	Default Service (prior to January 2, 2008)

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

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

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 results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year.  Operating results also can be affected by economic conditions, energy prices and the impact of energy efficiency measures on customer usage of electricity.

In connection with its approval of new electric service distribution base rates for Pepco and DPL in Maryland, effective June 16, 2007 (the 2007 Maryland Rate Order), the Maryland Public Service Commission (MPSC) approved a bill stabilization adjustment mechanism (BSA) for retail customers.  See “Regulatory and Other Matters – Rate Proceedings” in this Management’s Discussion and Analysis.  For customers to which the BSA applies, Pepco and DPL recognize distribution revenue based on an approved distribution charge per customer.  From a revenue recognition standpoint, the BSA thus decouples the distribution revenue recognized in a reporting period from the amount of power delivered during the period.  This change in the reporting of distribution revenue has the effect of eliminating changes in customer usage (whether due to weather conditions, energy prices, energy efficiency programs or other reasons) as a factor having an impact on reported revenue.  As a consequence, the only factors that will cause distribution revenue to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer.

The Competitive Energy business provides competitive generation, marketing and supply of electricity and gas, and related energy management services primarily in the mid-Atlantic region. These operations are conducted through subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv Energy) and Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), each of which is treated as a separate operating segment for financial reporting purposes.  For the three months ended March 31, 2008 and 2007, theoperating revenues of the Competitive Energy business (including revenue from intercompany transactions) were equal to 55%, and 46%, respectively, of PHI’s consolidated operating revenues, and the operating income of the Competitive Energy business (including operating income from intercompany transactions) was 45% and 26% of PHI’s consolidated operating income for the three months ended March 31, 2008 and 2007, respectively.  For the three months ended March 31, 2008 and 2007, amounts equal to 7% and 11% 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 and also supplies electricity to other wholesale market participants under long- and short-term bilateral contracts.  Conectiv Energy supplies electric power to Pepco, DPL and ACE to satisfy a portion of their Default Electricity Supply load, as well as default electricity supply load shares of other utilities within the PJM Interconnection, LLC (PJM) Regional Transmission Organization (RTO) and Independent System Operator - New

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England (ISONE) wholesale markets.  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 wholesale market.  Conectiv Energy also sells natural gas and fuel oil to very large end-users and to wholesale market participants under bilateral agreements.  PHI refers to these sales operations as Energy Marketing.

· Pepco Energy Services provides retail energy supply and energy services primarily to commercial, industrial, and governmental customers.  Pepco Energy Services sells electricity and natural gas to customers primarily in the mid-Atlantic region.  Pepco Energy Services provides energy-savings performance contracting services, owns and operates two district energy systems, 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 electric construction and maintenance services and streetlight asset management 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 predominately in the mid-Atlantic region.  The financial results of the Competitive Energy business can be significantly affected by wholesale and retail energy prices, the cost of fuel to operate the Conectiv Energy plants, and the cost of purchased energy necessary to meet its power and gas supply obligations.

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

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy sale-leaseback transactions with a book value at March 31, 2008 of approximately $1.4 billion.  This activity constitutes a fourth operating segment, which is designated as “Other Non-Regulated,” for financial reporting purposes.  For a discussion of PHI’s cross-border leasing transactions, see “Regulatory and Other Matters -- Federal Tax Treatment of Cross-Border Leases” in this Management’s Discussion and Analysis.

For additional information including information about PHI’s business strategy refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in PHI’s Form 10-K for the year ended December 31, 2007.

EARNINGS OVERVIEW

Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2007

PHI’s net income for the three months ended March 31, 2008 was $99.2 million, or $0.49 per share, compared to $51.6 million, or $0.27 per share, for the three months ended March 31, 2007.

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PHI’s net income for the three months ended March 31, 2008 and 2007, by operating segment, is set forth in the table below (in millions of dollars):

	2008	2007	Change
Power Delivery	$  47.4	$  33.2	$  14.2
Conectiv Energy	48.4	19.0	29.4
Pepco Energy Services	8.6	2.6	6.0
Other Non-Regulated	9.6	10.8	(1.2)
Corp. & Other	(14.8)	(14.0)	(0.8)
Total PHI Net Income	$  99.2	$  51.6	$  47.6

Discussion of Operating Segment Net Income Variances:

Power Delivery's $14.2 million increase in earnings is primarily due to the following:

·   $12.0 million increase due to the impact of the distribution base rate orders ($9.6 million related to Maryland which became effective in June 2007 for Pepco and DPL and $2.4 million related to the District of Columbia which became effective in February 2008 for Pepco).

·   $7.0 million increase due to favorable income tax adjustments primarily related to Financial Accounting Standards Board Interpretation No. 48 interest impact.

·   $6.5 million increase due to a FERC network transmission formula rate change in June 2007, reflecting increased transmission system investment and the elimination of a settlement adjustment in June 2006.

·   $3.1 million increase due to higher Default Electricity Supply margins primarily as a result of the sale of DPL’s Virginia electric distribution and default supply operations, which eliminated negative margins associated with Virginia Default Electricity Supply sales.

·   $10.8 million decrease primarily due to lower sales (primarily unfavorable impact of weather compared to 2007).

·   $4.1 million decrease due to higher operating and maintenance costs (primarily higher employee-related costs, tree trimming and bad debt expense).

Conectiv Energy's $29.4 million increase in earnings is primarily due to the following:

·   $30.3 million increase in Merchant Generation & Load Service primarily due to (i) an increase of $19.4 million primarily due to Conectiv Energy's generation units' operating flexibility and dual-fuel capability, and firm natural gas transportation and storage positions, (ii) an increase of $9.1 million due to higher PJM capacity prices net of capacity hedges, (iii) an increase of $5.4 million due to unrealized fuel gains,  (iv) an increase of $4.9 million due to congestion, and (v) an increase of $4.1 million due to favorable utility default electricity supply contracts and associated hedges in the New England market, partially offset by (vi) a decrease of $7.1 million due to

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lower output and generation spark spreads, and (vii) a decrease of $5.5 million due to less favorable realized hedges and default electricity supply contracts in PJM.

·   $2.3 million decrease primarily due to higher plant maintenance costs.

Pepco Energy Services' $6.0 million increase in earnings is primarily due to the following:

·   $8.5 million increase from its retail energy supply businesses resulting from (i) a $5.7 million increase from its retail electricity business due to more favorable congestion costs, higher capacity prices and higher electric delivery volumes and (ii) a $2.8 million increase from its retail natural gas supply business due to higher volumes and a favorable true-up of natural gas deliveries.

·   $2.5 million decrease from the energy services businesses primarily due to lower energy-savings performance activities.

CONSOLIDATED RESULTS OF OPERATIONS

The following results of operations discussion is for the three months ended March 31, 2008, compared to the three months ended March 31, 2007.  All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

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

	2008		2007		Change
Power Delivery	$	1,295.5	$	1,275.1	$	20.4
Conectiv Energy		822.7		496.1		326.6
Pepco Energy Services		620.7		509.9		110.8
Other Non-Regulated		18.6		19.3		(.7)
Corp. & Other		(116.6)		(121.6)		5.0
Total Operating Revenue	$	2,640.9	$	2,178.8	$	462.1

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Power Delivery Business

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

	2008		2007		Change
Regulated T&D Electric Revenue	$	380.1	$	350.9	$	29.2
Default Supply Revenue		783.8		794.8		(11.0)
Other Electric Revenue		15.9		16.6		(.7)
Total Electric Operating Revenue		1,179.8		1,162.3		17.5
Regulated Gas Revenue		91.7		101.7		(10.0)
Other Gas Revenue		24.0		11.1		12.9
Total Gas Operating Revenue		115.7		112.8		2.9
Total Power Delivery Operating Revenue	$	1,295.5	$	1,275.1	$	20.4

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

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

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

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

Other Gas Revenue consists of DPL’s off-system natural gas sales and the sale of excess system capacity.

In response to an order issued on January 18, 2008 by the New Jersey Board of Public Utilities (NJBPU) regarding changes to ACE’s retail transmission rates, ACE has established deferred accounting treatment for the difference between the rates that ACE is authorized to charge its customers for the transmission of default electricity supply and the cost that ACE incurs based on FERC-approved transmission formula rates.  Under the deferral arrangement, any over or under recovery is deferred pending an adjustment of retail rates in a future proceeding.

Effective January 1, 2008, ACE’s retail transmission revenue is being recorded as Default Supply Revenue, rather than as Regulated T&D Electric Revenue, thereby conforming to the practice of PHI’s other utility subsidiaries, which previously established deferred accounting

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treatment for any over or under recovery of retail transmission rates relative to the cost incurred based on FERC-approved transmission formula rates.  In addition, ACE’s retail transmission revenue for the period prior to January 1, 2008 has been reclassified to Default Supply Revenue in order to conform to current period presentation.

Electric Operating Revenue

Regulated T&D Electric Revenue
	2008		2007		Change
Residential	$	133.5	$	136.3	$	(2.8)
Commercial		160.9		156.4		4.5
Industrial		6.0		6.0		-
Other		79.7		52.2		27.5
Total Regulated T&D Electric Revenue	$	380.1	$	350.9	$	29.2

Other Regulated T&D Electric Revenue consists primarily of (i) transmission service revenue, (ii) revenue from the resale of energy and capacity under power purchase agreements between Pepco and unaffiliated third parties in the PJM RTO market, and (iii) either (a) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that Pepco and DPL are entitled to earn based on the distribution charge per customer approved in the 2007 Maryland Rate Order or (b) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment).

Regulated T&D Electric Sales (Gigawatt hours (GWh))
	2008	2007		Change
Residential	4,485		4,842	(357)
Commercial	6,685		6,731	(46)
Industrial	880		915	(35)
Other	70		69	1
Total Regulated T&D Electric Sales	12,120		12,557	(437)

Regulated T&D Electric Customers (in thousands)
	2008		2007		Change
Residential		1,604		1,612		(8)
Commercial		194		196		(2)
Industrial		2		2		-
Other		2		2		-
Total Regulated T&D Electric Customers		1,802		1,812		(10)

The change in the number of Regulated T&D Electric customers was primarily due to the sale of DPL’s Virginia distribution business on January 2, 2008, which resulted in a decrease of approximately 19,000 residential customers and 3,000 commercial customers.

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

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

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

Regulated T&D Electric Revenue increased by $29.2 million primarily due to the following: (i) $15.2 million increase in Other Regulated T&D Electric Revenue from the resale of energy and capacity purchased under the power purchase agreement between Panda-Brandywine, L.P. (Panda) and Pepco (the Panda PPA), (offset in Fuel and Purchased Energy and Other Services Cost of Sales), (ii) $9.6 million increase in transmission service revenue primarily due to an increase in the FERC formula rates in June 2007, (iii) $8.3 million increase due to a 2007 Maryland Rate Order that became effective in June 2007, which includes a positive $2.5 million Revenue Decoupling Adjustment, (iv) $2.2 million increase due to a 2008 District of Columbia Rate Order that became effective in February 2008, (v) $1.9 million increase due to higher pass-through revenue primarily resulting from tax rate increases in the District of Columbia (offset primarily in Other Taxes), partially offset by (vi) $6.7 million decrease due to lower weather-related sales (a 9% decrease in Heating Degree Days), and (vii) $2.7 million decrease due to the sale of DPL’s Virginia distribution business.

Default Electricity Supply

Default Supply Revenue
	2008		2007		Change
Residential	$	450.8	$	456.2	$	(5.4)
Commercial		228.5		241.9		(13.4)
Industrial		18.7		20.6		(1.9)
Other		85.8		76.1		9.7
Total Default Supply Revenue	$	783.8	$	794.8	$	(11.0)

Other Default Supply Revenue consists primarily of revenue from the resale of energy and capacity under non-utility generating contracts between ACE and unaffiliated third parties (NUGs) in the PJM RTO market.

Default Electricity Supply Sales (GWh)
	2008		2007		Change
Residential		4,345		4,723		(378)
Commercial		2,183		2,398		(215)
Industrial		157		219		(62)
Other		26		43		(17)
Total Default Electricity Supply Sales		6,711		7,383		(672)

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Default Electricity Supply Customers (in thousands)
	2008		2007		Change
Residential		1,566		1,580		(14)
Commercial		163		168		(5)
Industrial		1		1		-
Other		2		2		-
Total Default Electricity Supply Customers		1,732		1,751		(19)

The change in the number of Default Electricity Supply customers was primarily due to the sale of DPL’s Virginia default supply business on January 2, 2008, which resulted in a decrease of approximately 19,000 residential customers and 3,000 commercial customers.

Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales, decreased by $11.0 million primarily due to the following: (i) $21.8 million decrease due to lower weather-related sales (a 9% decrease in Heating Degree Days), (ii) $19.9 million decrease primarily due to commercial and industrial customers electing to purchase an increased amount of electricity from competitive suppliers, (iii) $10.9 million decrease due to differences in consumption among the various customer rate classes, (iv) $6.9 decrease due to the sale of DPL’s Virginia default supply business, partially offset by (v) $38.5 million increase in market-based Default Electricity Supply rates, and (vi) $10.0 million increase in wholesale energy revenues due to the sale in PJM RTO at higher market prices of electricity purchased from NUGs.

Gas Operating Revenue

Regulated Gas Revenue
	2008		2007		Change
Residential	$	56.7	$	62.0	$	(5.3)
Commercial		31.1		35.3		(4.2)
Industrial		1.8		2.9		(1.1)
Transportation and Other		2.1		1.5		.6
Total Regulated Gas Revenue	$	91.7	$	101.7	$	(10.0)

Regulated Gas Sales (billion cubic feet)
	2008		2007		Change
Residential		3.8		4.1		(.3)
Commercial		2.2		2.5		(.3)
Industrial		.2		.3		(.1)
Transportation and Other		2.3		2.0		.3
Total Regulated Gas Sales		8.5		8.9		(.4)

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Regulated Gas Customers (in thousands)
	2008		2007		Change
Residential		113		112		1
Commercial		9		10		(1)
Industrial		-		-		-
Transportation and Other		-		-		-
Total Regulated Gas Customers		122		122		-

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

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

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

Regulated Gas Revenue decreased by $10.0 million primarily due to (i) $6.3 million decrease due to Gas Cost Rate decreases effective April 2007 and November 2007, (ii) $3.7 million decrease due to warmer weather (a 7% decrease in Heating Degree Days), (iii) $2.2 million decrease due to differences in consumption among the various customer rate classes, partially offset by (iv) $2.2 million increase due to a base rate increase effective in April 2007.

Other Gas Revenue

Other Gas Revenue increased by $12.9 million primarily due to higher off-system sales (substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales).  The increase was due to (i) $7.5 million due to increased demand from third party electric generators and gas marketers during periods of available pipeline capacity driven by low demand for natural gas from regulated customers, resulting from warmer weather than 2007, and (ii) $4.8 million due to an increase in market prices.

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.

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Conectiv Energy Gross Margin

Merchant Generation & Load Service consists primarily of electric power, capacity and ancillary services sales from Conectiv Energy's generating plants; tolling arrangements entered into to 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.

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

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Conectiv Energy Gross Margin and Operating Statistics		March 31,				Change
		2008		2007
Operating Revenue ($ millions):
Merchant Generation & Load Service	$	506.2	$	247.3	$	258.9
Energy Marketing		316.5		248.8		67.7
Total Operating Revenue1	$	822.7	$	496.1	$	326.6
Cost of Sales ($ millions):
Merchant Generation & Load Service	$	391.2	$	183.4	$	207.8
Energy Marketing		301.2		233.6		67.6
Total Cost of Sales2	$	692.4	$	417.0	$	275.4
Gross Margin ($ millions):
Merchant Generation & Load Service	$	115.0	$	63.9	$	51.1
Energy Marketing		15.3		15.2		.1
Total Gross Margin	$	130.3	$	79.1	$	51.2
Generation Fuel and Purchased Power Expenses ($ millions) 3:
Generation Fuel Expenses 4,5
Natural Gas	$	32.9	$	31.7	$	1.2
Coal		16.3		15.3		1.0
Oil		11.7		11.3		.4
Other6		.7		.7		-
Total Generation Fuel Expenses	$	61.6	$	59.0	$	2.6
Purchased Power Expenses 5	$	268.4	$	102.2	$	166.2
Statistics:
Generation Output (MWh):
Base-Load 7		566,063		550,857		15,206
Mid-Merit (Combined Cycle) 8		375,355		383,722		(8,367)
Mid-Merit (Oil Fired) 9		(3,322)		71,706		(75,028)
Peaking		3,533		4,464		(931)
Tolled Generation		6,798		7,481		(683)
Total		948,427		1,018,230		(69,803)
Load Service Volume (MWh) 10		2,933,341		2,025,740		907,601
Average Power Sales Price 11 ($/MWh):
Generation Sales 4	$	93.52	$	74.97	$	18.55
Non-Generation Sales 12	$	88.20	$	70.68	$	17.52
Total	$	89.27	$	71.74	$	17.53
Average on-peak spot power price at PJM East Hub ($/MWh) 13	$	84.25	$	69.47	$	14.78
Average around-the-clock spot power price at PJM East Hub ($/MWh) 13	$	74.76	$	61.11	$	13.65
Average spot natural gas price at market area M3 ($/MMBtu)14	$	10.13	$	8.44	$	1.69
Weather (degree days at Philadelphia Airport): 15
Heating degree days		2,322		2,505		(183)
Cooling degree days		-		-		-

1 Includes $107.1 million and $117.2 million of affiliate transactions for 2008 and 2007, respectively.

2 Includes $3.7 million and $3.4 million of affiliate transactions for 2008 and 2007, respectively.  Also, excludes depreciation and amortization expense of $9.2 million and $9.3 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 intercompany tolling expenses.

4 Includes 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.  Generation output for these units was negative for the first quarter of 2008 because of station service consumption.

10 Consists 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’s revenue and cost of sales are higher in 2008 primarily due to increased default electricity supply volumes and higher energy commodity prices.  In 2008, Conectiv Energy expanded its default electricity supply business into the ISONE market.

Merchant Generation & Load Service gross margin increased $51.1 million primarily due to:

· An increase of approximately $32.3 million from increased margins during the winter period due in part to the seasonal peak demand for natural gas. Margins were higher due to: (i) sales of natural gas made possible by the dual-fuel capability of the combined cycle mid-merit units (fuel switching as more fully described below); (ii) spot and short-term sales of firm natural gas, and natural gas transportation and storage rights; (iii) gains on natural gas positions used to provide economic protection for certain power positions; and, (iv) the opportunities created by the mid-merit combined cycle unit’s operating flexibility (option value).  Fuel switching capability is the ability of the combined cycle mid-merit units to generate electricity utilizing either natural gas or oil, allowing the fuel not used to generate electricity to be sold, for purposes of maximizing the  combined margin from the sale of electricity and excess fuel.  The magnitude of the margin increase was greater than has been typically realized in the past due, in part, to significant fuel price increases in conjunction with less significant increases in power prices.

·               An increase of approximately $15.4 million due to higher PJM capacity prices net of capacity hedges.

· An increase of $9.2 million due to changes in the fair value of coal contracts and price ineffectiveness on fuel and power contracts accounted for as hedges.

·               An increase of approximately $8.2 million in generation margins due to higher congestion in 2008.

· An increase of $6.9 million due to utility default electricity supply contracts in the ISONE market, and associated hedges.

·               A decrease of $11.8 million resulting from lower generation margins due to lower coal spark-spreads and lower output.  During the quarter, generation output was down 7% primarily due to lower run-time at the oil-fired mid-merit units.  The decreased margins are partly attributable to fuel switching, the margins from which are included in the first paragraph above.

·              A decrease of $9.2 million resulting from realized power and fuel hedges including utility default electricity supply contracts in PJM.

Pepco Energy Services

Pepco Energy Services’ operating revenue increased $110.8 million primarily due to (i) an increase of $58.8 million due to higher volumes of retail electric load served at higher prices in 2008 due to customer acquisitions, (ii) an increase of $44.6 million due to higher natural gas

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volumes served in 2008 due to customer acquisitions, and (iii) an increase of $7.4 million due to increased construction activities in 2008.

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:

	2008		2007		Change
Power Delivery	$	835.9	$	831.2	$	4.7
Conectiv Energy		692.4		417.0		275.4
Pepco Energy Services		585.0		487.6		97.4
Corp. & Other		(115.5)		(120.7)		5.2
Total	$	1,997.8	$	1,615.1	$	382.7

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy and Other Cost of Sales, which is primarily associated with Default Electric Supply sales, increased by $4.7 million primarily due to: (i) $70.0 million increase in average energy costs, the result of new annual Default Electricity Supply contracts, (ii) $15.2 million increase for energy and capacity purchased under the Panda PPA (offset in Regulated T&D Electric Revenue), partially offset by (iii) $32.8 million decrease primarily due to commercial and industrial customers electing to purchase an increased amount of electricity from competitive suppliers, (iv) $22.2 million decrease due to lower weather-related sales, (v) $12.8 million decrease in the Default Electricity Supply and Deferred Gas Fuel deferral balances, and (vi) $12.7 million decrease due to the sale of DPL’s Virginia distribution and default supply businesses on January 2, 2008.  Fuel and Purchased Energy expense is substantially offset in Default Supply Revenue, Regulated Gas or Other Gas Revenue.

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 $97.4 million primarily due to (i) an increase of $47.5 million due to higher volumes of purchased electricity at higher prices in 2008 to serve increased retail customer load, (ii) an increase of $45.0 million due to higher volumes of natural gas purchased in 2008 to serve increased retail customer load, and (iii) an increase of $4.8 million due to increased construction activities in 2008.

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Other Operation and Maintenance

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

	2008		2007		Change
Power Delivery	$	171.5	$	161.7	$	9.8
Conectiv Energy		33.4		29.6		3.8
Pepco Energy Services		18.9		17.8		1.1
Other Non-Regulated		.6		1.9		(1.3)
Corp. & Other		(4.9)		(3.9)		(1.0)
Total	$	219.5	$	207.1	$	12.4

Other Operation and Maintenance expense of the Power Delivery segment increased by $9.8 million; however, excluding the favorable variance of $3.4 million primarily resulting from ACE's sale of the B.L. England electric generating facility in February 2007, Other Operation and Maintenance expense increased by $13.2 million.  The $13.2 million increase was primarily due to (i) $3.4 million net increase primarily due to 2007 recovery of stranded costs, (ii) $2.7 million increase due to higher bad debt expenses (partially offset in Deferred Electric Service Costs), (iii) $1.9 million increase in customer service operation expenses, (iv) $1.8 million increase in costs associated with Default Electricity Supply (primarily deferred and recoverable), (v) $1.5 million increase in legal expenses, (vi) $1.4 million increase in preventative maintenance and system operation costs, and (vii) $1.2 million increase in employee-related costs, partially offset by (viii) $2.3 million decrease in regulatory expenses.

Depreciation and Amortization

Depreciation and Amortization expenses decreased by $2.2 million to $90.9 million in 2008 from $93.1 million in 2007.  The decrease was primarily due to (i) $8.6 million decrease in depreciation due to a change in depreciation rates in accordance with the 2007 Maryland Rate Order, partially offset by (ii) $6.6 million increase in amortization related to a rate increase in October 2007 for Transition Bond Charge revenue (offset in Default Supply Revenue).

Other Taxes

Other Taxes increased by $2.9 million to $88.2 million in 2008 from $85.3 million in 2007.  The increase was primarily due to increased pass-throughs resulting from tax rate increases (partially offset in Regulated T&D Electric Revenue).

Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, decreased by $3.4 million to $24.7 million in 2008 from $28.1 million in 2007.  The decrease was primarily due to (i) $15.9 million net under-recovery associated with deferred energy costs, and (ii) $3.1 million net under-recovery associated with deferred transmission expenses, partially offset by (iii) $17.5 million net over-recovery associated with non-utility generation contracts between ACE and unaffiliated third parties.

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Gain on Sale of Assets

Gain on Sale of Assets increased $.6 million to $3.1 million in 2008, from $2.5 million in 2007.  The increase was primarily due to (i) $3.1 million gain on the sale of DPL’s Virginia distribution and default supply businesses, partially offset by (ii) $1.2 million gain in 2007 on the sale of accounts receivable.

Income Tax Expense

PHI’s effective tax rates for the years ended March 31, 2008 and 2007 were 34.6% and 37.8%, respectively.  The decrease in the effective tax rate in 2008 was primarily related to interest accrued on a tax claim filed with the Internal Revenue Service in March 2008.  The claim is for the treatment of casualty losses as current deductions (as opposed to being depreciated over their tax lives) on prior year returns currently under audit.

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 March 31, 2008, Pepco Holdings’ current assets on a consolidated basis totaled $2.3 billion and its current liabilities totaled $1.9 billion. At December 31, 2007, Pepco Holdings’ current assets totaled $2.0 billion and its current liabilities totaled $2.0 billion.  The increase in working capital from December 31, 2007 to March 31, 2008 is primarily due to the proceeds from long-term debt issuances in March 2008 and an increase in unrealized gains from derivative contracts.

At March 31, 2008, Pepco Holdings’ cash and current cash equivalents and its current restricted cash (cash that is available to be used only for designated purposes) totaled $344.2 million.  At December 31, 2007, Pepco Holdings’ cash and current cash equivalents and its current restricted cash totaled $69.6 million.  See “Capital Requirements -- Contractual Arrangements with Credit Rating Triggers or Margining Rights” herein for additional information.

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

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	As of March 31, 2008 (Millions of dollars)
Type	PHI Parent	Pepco	DPL	ACE	ACE Funding	Conectiv Energy	Pepco Energy Services	PCI	Conectiv	PHI Consolidated
Variable Rate   Demand Bonds	$      -	$       -	$104.8	$22.6	$      -	$    -	$24.3	$    -	$    -	$151.7
Commercial Paper	-			35.0	-	-	-	-	-	35.0
Total Short-Term Debt	$      -	$       -	$104.8	$57.6	$      -	$    -	$24.3	$    -	$    -	$186.7
Current Maturities   of Long-Term Debt   and Project   Funding	$      -	$100.0	$22.6	$35.0	$31.1	$    -	$8.3	$92.0	$    -	$289.0

	As of December 31, 2007 (Millions of dollars)
Type	PHI Parent	Pepco	DPL	ACE	ACE Funding	Conectiv Energy	Pepco Energy Services	PCI	Conectiv	PHI Consolidated
Variable Rate   Demand Bonds	$        -	$        -	$104.8	$22.6	$        -	$        -	$24.3	$      -	$        -	$151.7
Commercial Paper	-	84.0	24.0	29.1	-	-	-	-	-	137.1
Total Short-Term Debt	$        -	$  84.0	$128.8	$51.7	$        -	$        -	$24.3	$      -	$        -	$288.8
Current Maturities   of Long-Term Debt   and Project Funding	$        -	$128.0	$  22.6	$50.0	$31.0	$        -	$  8.6	$92.0	$        -	$332.2

Financing Activity During the Three Months Ended March 31, 2008

In January 2008, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $5.4 million on Series 2002-1 Bonds, Class A-1 and $2.2 million on Series 2003-1.

In March 2008, Pepco re-opened its November 2007 issue of $250 million 6.5% senior notes due November 2037 collateralized by first mortgage bonds, and issued an additional $250 million in principal amount of senior notes, increasing the outstanding principal amount of the 6.5% senior notes due November 2037 to $500 million. The net proceeds has been or will be used (a) to repay short-term debt, (b) to fund the retirement of $78 million of 6.5% first mortgage bonds on March 15, 2008, (c) to repay $50 million of 5.875% first mortgage bonds due October 15, 2008 at maturity and (d) for general corporate purposes. In connection with the offering, Pepco agreed that for so long as the senior notes are outstanding they will remain secured by a corresponding series of first mortgage bonds.

In March 2008, DPL entered into a $150 million, unsecured two year bank loan agreement.  Interest on the loan is based on LIBOR plus an applicable margin which varies according to DPL’s credit rating.  The net proceeds were used to repay short-term debt.

In March 2008, PHI subsidiaries purchased the following series of insured tax-exempt auction rate bonds that were issued by municipal authorities for the benefit of the PHI subsidiaries.  These purchases were made in response to disruption in the market for municipal auction rate securities that made it difficult for the remarketing agent to successfully remarket the bonds:

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· DPL purchased the following series of bonds issued by The Delaware Economic Development Authority: (i) $27.75 million of Exempt Facilities Revenue Refunding Bonds 2000B Series due 2030, (ii) $15 million of Exempt Facilities Revenue Refunding Bonds 2003A Series due 2038 and (iii) $15 million of Exempt Facilities Revenue Refunding Bonds 2002A Series due 2032.

        · ACE purchased $25 million of Pollution Control Revenue Refunding Bonds 2004A Series due 2029 issued by Cape May County.

Although these bonds are considered to be extinguished for accounting purposes, DPL and ACE intend to hold the bonds, while monitoring the market and evaluating the options for remarketing the bonds to the public.

In March 2008, ACE retired at maturity $15 million of medium-term notes with a weighted average interest rate of 6.79%.

Financing Activity Subsequent to March 31, 2008

In April 2008, ACE retired at maturity $1 million of 6.77% medium-term notes.

In April 2008, ACE Funding made principal payments of $5.1 million on Series 2002-1 Bonds, Class A-1 and $2.1 million on Series 2003-1.

For the reason discussed above, PHI subsidiaries in April purchased the following additional series of insured tax-exempt auction rate bonds:

· Pepco purchased $109.5 million of Pollution Control Revenue Refunding Bonds Series 2006 due 2022 issued by the Maryland Economic Development Corporation.

· DPL purchased the following series of bonds issued by the Delaware Economic Development Authority: (i) $20 million of Exempt Facilities Revenue Refunding Bonds 2001A Series due 2031, (ii) $4.5 million of Exempt Facilities Revenue Refunding Bonds 2001B Series due 2031 and (iii) $11.15 million of Exempt Facilities Revenue Refunding Bonds 2000A Series due 2030.

· ACE purchased (i) $23.15 million of Pollution Control Revenue Refunding Bonds Series 2004A due 2029 issued by Salem County and (ii) $6.5 million of Pollution Control Revenue Refunding Bonds Series 2004B due 2029 issued by Cape May County.

Although these bonds are considered to be extinguished for accounting purposes, each of the companies intends to hold the bonds, while monitoring the market and evaluating the options for remarketing the bonds to the public.

In May 2008, Pepco completed two $25 million short-term bank loans, one maturing on September 30, 2008 and one on April 30, 2009.  Both are variable rate loans and Pepco has the option to repay the loans on any interest reset date without penalty.  Proceeds were used to temporarily finance the repurchase of Pepco insured tax exempt auction rate bonds.

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Cash Flow Activity

PHI’s cash flows for the three months ended March 31, 2008 and 2007 are summarized below.

	Cash Source / (Use)
		2008		2007
		(Millions of dollars)
Operating activities	$	347.0	$	257.5
Investing activities		(132.3)		(120.0)
Financing activities		46.4		(104.6)
Net increase in cash and cash equivalents	$	261.1	$	32.9

Operating Activities

Cash flows from operating activities during the three months ended March 31, 2008 and 2007 are summarized below.

	Cash Source
		2008		2007
		(Millions of dollars)
Net income	$	99.2	$	51.6
Non-cash adjustments to net income		95.7		100.6
Changes in working capital		152.1		105.3
Net cash from operating activities	$	347.0	$	257.5

Net cash from operating activities was $89.5 million higher for the three months ended March 31, 2008, compared to the same period in 2007.  In addition to the increase in net income, changes in working capital increased $46.8 million primarily attributable to the change in cash collateral requirements associated with Competitive Energy activities.

Investing Activities

Cash flows from investing activities during the three months ended March 31, 2008 and 2007 are summarized below.

	Cash (Use) / Source
		2008		2007
		(Millions of dollars)
Construction expenditures	$	(170.9)	$	(127.0)
Cash proceeds from sale of:
Other assets		50.6		10.6
All other investing cash flows, net		(12.0)		(3.6)
Net cash used by investing activities	$	(132.3)	$	(120.0)

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Net cash used by investing activities increased $12.3 million for the three months ended March 31, 2008 compared to the same period in 2007.  The increase was due in part to:  (i) a $43.9 million increase in capital expenditures, $29.2 million of which relates to Power Delivery, offset by (ii) an increase of $40.0 million in cash proceeds from the sale of assets.  The increase in Power Delivery capital expenditures is primarily attributable to new customer services, distribution reliability, and transmission.  The proceeds from the sale of assets in 2008 consisted primarily of $50.1 million received from DPL’s sale of its Virginia operations.  Proceeds from the sale of assets in 2007 consisted primarily of $9.0 million received from the sale of the B.L. England generating facility.

Financing Activities

Cash flows from financing activities during the three months ended March 31, 2008 and 2007 are summarized below.

	Cash (Use) / Source
		2008		2007
		(Millions of dollars)
Dividends paid on common and preferred stock	$	(54.3)	$	(50.2)
Common stock issued for the Dividend Reinvestment Plan		7.2		7.0
Issuance of common stock		12.5		19.9
Redemption of preferred stock of subsidiaries		-		(18.2)
Issuances of long-term debt		400.1		.3
Reacquisition of long-term debt		(183.3)		(88.1)
(Repayments) issuances of short-term debt, net		(102.1)		32.5
All other financing cash flows, net		(33.7)		(7.8)
Net cash from (used by) financing activities	$	46.4	$	(104.6)

Net cash from financing activities increased $151.0 million for the three months ended March 31, 2008, compared to the same period in 2007.

Changes in Outstanding Common Stock.  The increase in common stock outstanding in the first quarter of 2008 is primarily attributable to the issuance of performance based shares under the Long-Term Incentive Plan.  Under the LTIP, PHI issued 544,704 shares of common stock during the three months ended March 31, 2008, and 513,743 shares of common stock during the three months ended March 31, 2007.  In addition, under PHI’s Shareholder Dividend Reinvestment Plan, 289,344 shares of common stock were issued during the three months ended March 31, 2008 and 242,054 were issued during the three months ended March 31, 2007.

Common Stock Dividends.  Common stock dividend payments were $54.2 million in the first quarter of 2008 and $50.1 million in the first quarter of 2007.  The increase in common dividends paid in 2008 was the result of additional shares outstanding, primarily from the PHI sale of 6.5 million shares of common stock in November 2007 and a quarterly dividend increase from 26 cents per share to 27 cents per share beginning in the first quarter of 2008.

Changes in Outstanding Preferred Stock.  Preferred stock redemptions in 2007 consisted of DPL’s redemption in January 2007, at prices ranging from 103% to 105% of par, of the

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following securities, representing all of DPL’s outstanding preferred stock, at an aggregate cost of $18.9 million:

· 19,809 shares of 4.00% Series, 1943 Redeemable Serial Preferred Stock,

· 39,866 shares of 3.70% Series, 1947 Redeemable Serial Preferred Stock,

· 28,460 shares of 4.28% Series, 1949 Redeemable Serial Preferred Stock,

· 19,571 shares of 4.56% Series, 1952 Redeemable Serial Preferred Stock,

· 25,404 shares of 4.20% Series, 1955 Redeemable Serial Preferred Stock, and

· 48,588 shares of 5.00% Series, 1956 Redeemable Serial Preferred Stock.

Changes in Outstanding Long-Term Debt.  Cash flows from the issuance and redemption of long-term debt in the first quarter of 2008 were attributable primarily to the transactions described under the heading “Financing Activity During the Three Months Ended March 31, 2008” above, which encompasses $400 million of the long-term debt issued in the first quarter of 2008 and $183.3 million in long-term debt redeemed in the first quarter of 2008.

Cash flows from redemption of long-term debt in 2007 were attributable to the following transactions, which encompass all of the $88.1 million in long-term debt redeemed in 2007:

· In January 2007, Pepco retired at maturity $35 million of 7.64% medium-term notes.

· In February 2007, DPL retired at maturity $11.5 million of medium-term notes with a weighted average interest rate of 7.08%.

· In January 2007, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $5.2 million on Series 2002-1 Bonds, Class A-1 and $2.1 million on Series 2003-1, Class A-1 with a weighted average interest rate of 2.89%.

· In February 2007, PCI retired at maturity $34.3 million of 7.62% medium-term notes.

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

Changes in Short-Term Debt.  In 2008, Pepco and DPL redeemed a total of $108.0 million in short-term debt with cash from capital contributions.

Sale of ACE Generating Facility

On February 8, 2007, ACE completed the sale of the B.L. England generating facility for a price of $9.0 million.  No gain or loss was realized on this sale.

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Capital Requirements

Capital Expenditures

Pepco Holdings' total capital expenditures for the three months ended March 31, 2008 totaled $170.9 million, of which $58.5 million was incurred by Pepco, $32.0 million was incurred by DPL, $57.0 million was incurred by ACE and $15.5 million was incurred by Conectiv Energy.  The remainder was incurred primarily by Pepco Energy Services.  The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability, and transmission.

In its Annual Report on Form 10-K for the year ended December 31, 2007, PHI projected the construction expenditures for its 230-mile, 500-kilovolt Mid-Atlantic Power Pathway Project (the MAPP Project) to be approximately $1 billion over a six-year period beginning in 2008.  This amount does not include the cost of significant 230 kilovolt support lines in Maryland and New Jersey to connect to the 500-kilovolt line, with an estimated cost of $200 million, and the additional cost of a direct current system underwater crossing of Chesapeake Bay, at an estimated cost of $375 million.  These enhancements have been recommended to PJM, and if approved, will increase PHI’s projected MAPP Project costs.

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

For a discussion of the history of PHI’s third party guarantees, indemnifications, obligations and off-balance sheet arrangements, see Note (12) “Commitments and Contingencies” to the Consolidated Financial Statements of PHI included as Part I, Item 1, in this Form 10-Q.

Dividends

On April 24, 2008, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable June 30, 2008, to shareholders of record on June 10, 2008.

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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.  The balances reflected in the table are stated gross, before the netting of collateral required by FIN 39-1.

Roll-forward of Mark-to-Market Energy Contract Net Assets For the Three Months Ended March 31, 2008 (Dollars are pre-tax and in millions)
	Proprietary Trading (a)	Other Energy Commodity (b)	Total
Total Marked-to-Market (MTM) Energy Contract Net   Assets at December 31, 2007	$          -	$18.1	$18.1
Total change in unrealized fair value	-	35.4	35.4
Less:  Reclassification to realized at settlement of contracts	-	(19.0)	(19.0)
Effective portion of changes in fair value - recorded     in Other Comprehensive Income	-	205.6	205.6
Cash flow hedge ineffectiveness - recorded in earnings	-	3.1	3.1
Total MTM Energy Contract Net Assets at March 31, 2008	$          -	$243.2	$243.2
Detail of MTM Energy Contract Net Assets at March 31, 2008 (see above)			Total
Current Assets (unrealized gains - derivative contracts)			$251.1
Noncurrent Assets (other assets)			69.8
Total MTM Energy Contract Assets			320.9
Current Liabilities (other current liabilities)			(58.7)
Noncurrent Liabilities (other liabilities)			(19.0)
Total MTM Energy Contract Liabilities			(77.7)
Total MTM Energy Contract Net Assets			$243.2

Notes:
(a)	PHI does not engage in proprietary trading activities.
(b)	Includes all Statement of Financial Accounting Standards (SFAS) No. 133 hedge activity and non-proprietary trading activities marked-to-market through earnings.

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 March 31, 2008 and are subject to change as a result of changes in these factors:

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Maturity and Source of Fair Value of Mark-to-Market Energy Contract Net Assets (Liabilities) As of March 31, 2008 (Dollars are pre-tax and in millions)
	Fair Value of Contracts at March 31, 2008                           Maturities (a)
Source of Fair Value	2008	2009	2010	2011 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 (b)
Actively Quoted (i.e., exchange-traded) prices	$  10.7	$ 1.4	$ (1.7)	$   .3	$  10.7
Prices provided by other external sources (c)	153.7	50.8	22.4	.5	227.4
Modeled	4.6	.9	(3.0)	2.6	5.1
Total	$169.0	$53.1	$17.7	$ 3.4	$243.2

Notes:
(a)	Indicated maturity is based on contract settlement or delivery date(s).
(b)	Includes all SFAS No. 133 hedge activity and non-proprietary trading activities marked-to-market through AOCI or on the Statement of Earnings, as required.
(c)	Prices provided by other external sources reflect information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.

Contractual Arrangements with Credit Rating Triggers or Margining Rights

Under certain contractual arrangements entered into by PHI’s subsidiaries in connection with the Competitive Energy business and other transactions, the subsidiary may be required to provide cash collateral or letters of credit as security for its contractual obligations if the credit ratings of the subsidiary are downgraded.  In the event of a downgrade, the amount required to be posted would depend on the amount of the underlying contractual obligation existing at the time of the downgrade.  Based on contractual provisions in effect at March 31, 2008, PHI estimates that if a one-level downgrade in the credit rating of PHI and all of its affected subsidiaries were to occur, the additional aggregate cash collateral or letters of credit amount required would be $418 million for PHI and each of its relevant subsidiaries.  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.

Many of the contractual arrangements entered into by PHI’s subsidiaries in connection with Competitive Energy and Default Electricity Supply activities include margining rights pursuant to which the PHI subsidiary or a counterparty may request collateral if the market value of the contractual obligations reaches levels in excess of the credit thresholds established in the

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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 March 31, 2008, Pepco Holdings’ subsidiaries engaged in Competitive Energy activities and Default Electricity Supply activities are holding net cash collateral in the amount of $26.5 million in connection with these activities.

REGULATORY AND OTHER MATTERS

For a discussion of material pending matters such as regulatory and legal proceedings, and other commitments and contingencies, see Note (12) “Commitments and Contingencies” to the Consolidated Financial Statements of PHI included as Part I, Item 1 in this Form 10-Q.

CRITICAL ACCOUNTING POLICIES

For a discussion of Pepco Holdings’ critical accounting policies, please refer to Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in Pepco Holdings’ Annual Report on Form 10-K for the year ended December 31, 2007.  No material changes to Pepco Holdings’ critical accounting policies occurred during the first quarter of 2008.

New Accounting Standards and Pronouncements

For information concerning new accounting standards and pronouncements that have recently been adopted by PHI and its subsidiaries or that one or more of the companies will be required to adopt on or before a specified date in the future, see Note (3) “Newly Adopted Accounting Standards” and Note (4) “Recently Issued Accounting Standards, Not Yet Adopted” to the consolidated financial statements of PHI set forth in Item 1 of this Form 10-Q.

FORWARD-LOOKING STATEMENTS

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

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

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· Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;

· Changes in and compliance with environmental and safety laws and policies;

· Weather conditions;

· Population growth rates and demographic patterns;

· Competition for retail and wholesale customers;

· General economic conditions, including potential negative impacts resulting from an economic downturn;

· Growth in demand, sales and capacity to fulfill demand;

· Changes in tax rates or policies or in rates of inflation;

· Changes in accounting standards or practices;

· Changes in project costs;

· Unanticipated changes in operating expenses and capital expenditures;

· The ability to obtain funding in the capital markets on favorable terms;

· Rules and regulations imposed by Federal and/or state regulatory commissions, PJM and other regional transmission organizations (New York Independent System Operator, ISONE), the North American Electric Reliability Council and other applicable electric reliability organizations;

· Legal and administrative proceedings (whether civil or criminal) and settlements that influence PHI’s business and profitability;

· Pace of entry into new markets;

· Volatility in market demand and prices for energy, capacity and fuel;

· Interest rate fluctuations and credit market concerns; and

· Effects of geopolitical events, including the threat of domestic terrorism.

Any forward-looking statements speak only as to the date of this Quarterly Report and Pepco Holdings undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for Pepco Holdings to predict all such factors, nor can Pepco Holdings assess the impact of any such factor on Pepco Holdings’ business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

  AND RESULTS OF OPERATIONS

POTOMAC ELECTRIC POWER COMPANY

GENERAL OVERVIEW

Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in Washington, D.C. and major portions of Montgomery County and Prince George’s County in suburban Maryland.  Pepco provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier, in both the District of Columbia and Maryland.  Default Electricity Supply is known as Standard Offer Service in both the District of Columbia and Maryland.  Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.1 million.  As of March 31, 2008, approximately 58% of delivered electricity sales were to Maryland customers and approximately 42% were to Washington, D.C. customers.

In connection with its approval of new electric service distribution base rates for Pepco in Maryland, effective June 16, 2007 (the 2007 Maryland Rate Order), the Maryland Public Service Commission (MPSC) approved a bill stabilization adjustment mechanism (BSA) for retail customers.  For customers to which the BSA applies, Pepco recognizes distribution revenue based on an approved distribution charge per customer.  From a revenue recognition standpoint, the BSA thus decouples the distribution revenue recognized in a reporting period from the amount of power delivered during the period.  This change in the reporting of distribution revenue has the effect of eliminating changes in customer usage (whether due to weather conditions, energy prices, energy efficiency programs or other reasons) as a factor having an impact on reported revenue.  As a consequence, the only factors that will cause distribution revenue to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer.

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

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RESULTS OF OPERATIONS

The accompanying results of operations discussion is for the three months ended March 31, 2008, compared to the three months ended March 31, 2007.  Other than this disclosure, information under this item has been omitted in accordance with General Instruction H to the Form 10-Q.  All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2008		2007		Change
Regulated T&D Electric Revenue	$	218.0	$	196.7	$	21.3
Default Supply Revenue		298.5		302.0		(3.5)
Other Electric Revenue		8.0		7.9		.1
Total Operating Revenue	$	524.5	$	506.6	$	17.9

The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated Transmission and Distribution (T&D) Electric Revenue and Default Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the delivery of electricity, including the delivery of Default Electricity Supply, to Pepco’s customers within its service territory at regulated rates.  Regulated T&D Electric Revenue also includes transmission service revenue that Pepco receives as a transmission owner from PJM Interconnection, LLC (PJM).

Default Supply Revenue is the revenue received for Default Electricity Supply.  The costs related to Default Electricity Supply are included in Fuel and Purchased Energy expense.

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

Regulated T&D Electric

Regulated T&D Electric Revenue	2008		2007		Change
Residential	$	57.3	$	58.4	$	(1.1)
Commercial		117.7		113.3		4.4
Industrial		-		-		-
Other		43.0		25.0		18.0
Total Regulated T&D Electric Revenue	$	218.0	$	196.7	$	21.3

Other Regulated T&D Electric Revenue consists primarily of (i) transmission service revenue, (ii) revenue from the resale of energy and capacity under power purchase agreements between Pepco and unaffiliated third parties in the PJM Regional Transmission Organization (PJM RTO) market, and (iii) either (a) a positive adjustment equal to the amount by which

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revenue from Maryland retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the distribution charge per customer approved in the 2007 Maryland Rate Order or (b) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment).

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2008		2007		Change
Residential		2,067		2,202		(135)
Commercial		4,411		4,418		(7)
Industrial		-		-		-
Other		45		44		1
Total Regulated T&D Electric Sales		6,523		6,664		(141)

Regulated T&D Electric Customers (in thousands)	2008		2007		Change
Residential		687		683		4
Commercial		73		73		-
Industrial		-		-		-
Other		-		-		-
Total Regulated T&D Electric Customers		760		756		4

Regulated T&D Electric Revenue increased by $21.3 million primarily due to the following: (i) $15.2 million increase in Other Regulated T&D Electric Revenue from the resale of energy and capacity purchased under the power purchase agreement between Panda-Brandywine, L.P. (Panda) and Pepco (the Panda PPA) (offset in Fuel and Purchased Energy), (ii) $2.5 million increase due to a 2007 Maryland Rate Order that became effective in June 2007, which includes a positive $1.1 million Revenue Decoupling Adjustment, (iii) $2.2 million increase due to a 2008 District of Columbia Rate Order that became effective in February 2008, (iv) $1.9 million increase due to higher pass-through revenue primarily resulting from tax rate increases in the District of Columbia (offset primarily in Other Taxes), partially offset by (v) $4.1 million decrease due to lower weather-related sales (a 13% decrease in Heating Degree Days).

Default Electricity Supply

Default Supply Revenue	2008		2007		Change
Residential	$	199.9	$	193.5	$	6.4
Commercial		96.8		107.3		(10.5)
Industrial		-		-		-
Other		1.8		1.2		.6
Total Default Supply Revenue	$	298.5	$	302.0	$	(3.5)

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Default Electricity Supply Sales (GWh)	2008		2007		Change
Residential		1,965		2,096		(131)
Commercial		916		1,102		(186)
Industrial		-		-		-
Other		3		18		(15)
Total Default Electricity Supply Sales		2,884		3,216		(332)

Default Electricity Supply Customers (in thousands)	2008		2007		Change
Residential		658		654		4
Commercial		52		53		(1)
Industrial		-		-		-
Other		-		-		-
Total Default Electricity Supply Customers		710		707		3

Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy, decreased by $3.5 million primarily due to the following: (i) $16.2 million decrease primarily due to commercial customers electing to purchase an increased amount of electricity from competitive suppliers, (ii) $12.5 million decrease due to lower weather-related sales (a 13% decrease in Heating Degree Days), partially offset by (iii) $25.7 million increase due to annual increases in market-based Default Electricity Supply rates.

The following table shows the percentages of Pepco’s total sales by jurisdiction that are derived from customers receiving Default Electricity Supply in that jurisdiction from Pepco.  Amounts are for the three months ended March 31.

	2008		2007
Sales to District of Columbia customers		32%		40%
Sales to Maryland customers		53%		55%

Operating Expenses

Fuel and Purchased Energy

Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply sales, increased by $11.0 million to $307.5 million in 2008 from $296.5 million in 2007.  The increase was primarily due to following (i) $33.3 million increase in average energy costs, the result of new annual Default Electricity Supply contracts, (ii) $15.2 million increase for energy and capacity purchased under the Panda PPA (offset in Regulated T&D Electric Revenue), partially offset by (iii) $18.1 million decrease primarily due to commercial customers electing to purchase an increased amount of electricity from competitive suppliers, (iv) $12.1 million decrease due to lower weather-related sales, and (v) $6.8 million decrease in the Default Electricity Supply deferral balance.  Fuel and Purchased Energy expense is substantially offset in Default Supply Revenue

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Other Operation and Maintenance

Other Operation and Maintenance expense decreased by $.7 million to $70.3 million in 2008 from $71.0 million in 2007.  The decrease was primarily due to the following: (i) $2.2 million decrease in regulatory expenses, partially offset by (ii) $1.3 million increase in employee-related costs.

Depreciation and Amortization

Depreciation and Amortization expenses decreased by $7.5 million to $34.4 million in 2008 from $41.9 million in 2007.  The decrease was primarily due to a change in depreciation rates in accordance with the 2007 Maryland Rate Order.

Other Taxes

Other Taxes increased by $1.3 million to $69.6 million in 2008 from $68.3 million in 2007 primarily due to increased pass-throughs resulting from tax rate increases in the District of Columbia (partially offset in Regulated T&D Electric Revenue).

Other Income (Expenses)

Other Expenses (which are net of other income) increased by $2.3 million to a net expense of $17.3 million in 2008 from a net expense of $15.0 million in 2007.  This increase was primarily due an increase in interest expense related to long-term debt.

Income Tax Expense

Pepco’s effective tax rates for the three months ended March 31, 2008 and 2007 were 40.2% and 40.0%, respectively.  The change in the rate resulted from an increase in asset removal costs offset by interest accrued on a tax claim filed with the IRS in March 2008.  The claim is for the treatment of casualty losses as current deductions (as opposed to being depreciated over their tax lives) on prior year returns currently under audit.

Capital Requirements

Capital Expenditures

Pepco's capital expenditures for the three months ended March 31, 2008, totaled $58.5 million.  These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

In its Annual Report on Form 10-K for the year ended December 31, 2007, PHI projected the construction expenditures for its 230-mile, 500-kilovolt Mid-Atlantic Power Pathway Project (the MAPP Project) to be approximately $1 billion over a six-year period beginning in 2008.  This amount does not include the cost of significant 230 kilovolt support lines in Maryland and New Jersey to connect to the 500-kilovolt line, with an estimated cost of $200 million, and the additional cost of a direct current system underwater crossing of Chesapeake Bay, at an estimated cost of $375 million.  These enhancements have been recommended to PJM, and if approved, will increase PHI’s projected MAPP Project costs.

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FORWARD-LOOKING STATEMENTS

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

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

· Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;

· Changes in and compliance with environmental and safety laws and policies;

· Weather conditions;

· Population growth rates and demographic patterns;

· Competition for retail and wholesale customers;

· General economic conditions, including potential negative impacts resulting from an economic downturn;

· Growth in demand, sales and capacity to fulfill demand;

· Changes in tax rates or policies or in rates of inflation;

· Changes in 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, PJM, the North American Electric Reliability Council and other applicable electric reliability organizations;

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· Legal and administrative proceedings (whether civil or criminal) and settlements that influence Pepco’s business and profitability;

· Volatility in market demand and prices for energy, capacity and fuel;

· Interest rate fluctuations and credit market concerns; and

· Effects of geopolitical events, including the threat of domestic terrorism.

Any forward-looking statements speak only as to the date of this Quarterly Report and Pepco undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for Pepco to predict all 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 (until the sale of its Virginia operations on January 2, 2008).  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 (until the sale of its Virginia operations on January 2, 2008), and as Standard Offer Service in Maryland and in Delaware. DPL’s electricity distribution service territory covers approximately 5,000 square miles and has a population of approximately 1.2 million.  As of March 31, 2008, approximately 66% of delivered electricity sales were to Delaware customers and approximately 34% were to Maryland customers.  In northern Delaware, DPL also supplies and distributes natural gas to retail customers and provides transportation-only services to retail customers that purchase natural gas from other suppliers.  DPL’s natural gas distribution service territory covers approximately 275 square miles and has a population of approximately .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 the Federal Energy Regulatory Commission under PUHCA 2005.

On January 2, 2008, DPL completed (i) the sale of its retail electric distribution business on the Eastern Shore of Virginia to A&N Electric Cooperative (A&N) for a purchase price of approximately $48.8 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission business located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase price of approximately $5.4 million, after closing adjustments.  Each of A&N and ODEC assumed certain post-closing liabilities and unknown pre-closing liabilities related to the respective assets they are purchasing (including, in the A&N transaction, most environmental liabilities), except that DPL remained liable for unknown pre-closing liabilities if they become known within six months after the January 2, 2008 closing date.  These sales resulted in a $3.1 million pre-tax gain ($1.8 million after-tax), which was recorded during the first quarter of 2008.

In connection with its approval of new electric service distribution base rates for DPL in Maryland, effective June 16, 2007 (the 2007 Maryland Rate Order), the Maryland Public Service Commission (MPSC) approved a bill stabilization adjustment mechanism (BSA) for retail customers.  For customers to which the BSA applies, DPL recognizes distribution revenue based on an approved distribution charge per customer.  From a revenue recognition standpoint, the BSA thus decouples the distribution revenue recognized in a reporting period from the amount of power delivered during the period.  This change in the reporting of distribution revenue has the effect of eliminating changes in customer usage (whether due to weather conditions, energy

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prices, energy efficiency programs or other reasons) as a factor having an impact on reported revenue.  As a consequence, the only factors that will cause distribution revenue to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer.

RESULTS OF OPERATIONS

The accompanying results of operations discussion is for the three months ended March 31, 2008, compared to the three months ended March 31, 2007.  Other than this disclosure, information under this item has been omitted in accordance with General Instruction H to the Form 10-Q.  All amounts in the tables (except sales and customers) are in millions of dollars.

Electric Operating Revenue

		2008		2007	Change
Regulated T&D Electric Revenue	$	87.5	$	82.2	$	5.3
Default Supply Revenue		202.7		221.6		(18.9)
Other Electric Revenue		4.6		4.9		(.3)
Total Electric Operating Revenue	$	294.8	$	308.7	$	(13.9)

The table above shows the amount of Electric Operating Revenue earned that is subject to price regulation (Regulated Transmission and Distribution (T&D) Electric Revenue and Default Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the delivery of electricity, including the delivery of Default Electricity Supply, to DPL’s customers within its service territory at regulated rates.  Regulated T&D Electric Revenue also includes transmission service revenue that DPL receives as a transmission owner from PJM Interconnection, LLC (PJM).

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 expense.

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

Regulated T&D Electric

Regulated T&D Electric Revenue		2008		2007	Change
Residential	$	43.7	$	44.0	$	(.3)
Commercial		21.6		21.1		.5
Industrial		2.7		2.9		(.2)
Other		19.5		14.2		5.3
Total Regulated T&D Electric Revenue	$	87.5	$	82.2	$	5.3

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Other Regulated T&D Electric Revenue consists primarily of (i) transmission service revenue, and (ii) either (a) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the distribution charge per customer approved in the 2007 Maryland Rate Order or (b) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment).

Regulated T&D Electric Sales (Gigawatt hours (Gwh))	2008	2007	Change
Residential	1,397	1,566		(169)
Commercial	1,245	1,299		(54)
Industrial	612	666		(54)
Other	12	12		-
Total Regulated T&D Electric Sales	3,266	3,543		(277)

Regulated T&D Electric Customers (in thousands)	2008	2007	Change
Residential	437	453		(16)
Commercial	58	60		(2)
Industrial	1	1		-
Other	1	1		-
Total Regulated T&D Electric Customers	497	515		(18)

The change in the number of Regulated T&D Electric customers was primarily due to the sale of DPL’s Virginia distribution business on January 2, 2008, which resulted in a decrease of approximately 19,000 residential customers and 3,000 commercial customers.

Regulated T&D Electric Revenue increased by $5.3 million primarily due to the following: (i) $5.8 million increase due to a 2007 Maryland Rate Order that became effective in June 2007, which includes a positive $1.4 million Revenue Decoupling Adjustment, (ii) $3.7 million increase in transmission service revenues primarily due to an increase in Federal Energy Regulatory Commission formula rates in June 2007, partially offset by (iii) $2.7 million decrease due to the sale of the Virginia distribution business, and (iv) $1.8 million decrease due to lower weather-related sales (a 5% decrease in Heating Degree Days).

Default Electricity Supply

Default Supply Revenue		2008		2007	Change
Residential	$	142.4	$	154.0	$	(11.6)
Commercial		50.3		56.3		(6.0)
Industrial		7.5		9.7		(2.2)
Other		2.5		1.6		.9
Total Default Supply Revenue	$	202.7	$	221.6	$	(18.9)

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Default Electricity Supply Sales (GWh)	2008	2007	Change
Residential	1,359	1,553		(194)
Commercial	519	548		(29)
Industrial	89	133		(44)
Other	10	12		(2)
Total Default Electricity Supply Sales	1,977	2,246		(269)

Default Electricity Supply Customers (in thousands)	2008	2007	Change
Residential	428	450		(22)
Commercial	48	52		(4)
Industrial	-	-		-
Other	1	1		-
Total Default Electricity Supply Customers	477	503		(26)

The change in the number of Default Electricity Supply customers was primarily due to the sale of DPL’s Virginia default supply business on January 2, 2008, which resulted in a decrease of approximately 19,000 residential customers and 3,000 commercial customers.

Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy, decreased by $18.9 million primarily due to the following: (i) $6.9 million decrease due to lower weather-related sales (a 5% decrease in Heating Degree Days), (ii) $6.9 million decrease due to the sale of the Virginia default supply business on January 2, 2008, and (iii) $6.6 million decrease due to differences in consumption among various customer rate classes, partially offset by (iv) $2.5 million increase due to annual increases in market-based Default Electricity Supply rates.

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.  Amounts are for the three months ended March 31.

	2008	2007
Sales to Delaware customers	56%	57%
Sales to Maryland customers	70%	74%
Sales to Virginia customers	-%	89%

Natural Gas Operating Revenue

	2008		2007		Change
Regulated Gas Revenue	$	91.7	$	101.7	$	(10.0)
Other Gas Revenue		24.0		11.1		12.9
Total Natural Gas Operating Revenue	$	115.7	$	112.8	$	2.9

The table above shows the amounts of Natural Gas Operating Revenue from sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject

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to price regulation (Other Gas Revenue).  Regulated Gas Revenue includes the revenue DPL receives for on-system natural gas delivered sales and the transportation of natural gas for customers.  Other Gas Revenue includes off-system natural gas sales and the release of excess system capacity.

Regulated Gas Revenue	2008		2007		Change
Residential	$	56.7	$	62.0	$	(5.3)
Commercial		31.1		35.3		(4.2)
Industrial		1.8		2.9		(1.1)
Transportation and Other		2.1		1.5		.6
Total Regulated Gas Revenue	$	91.7	$	101.7	$	(10.0)

Regulated Gas Sales (billion cubic feet)	2008		2007		Change
Residential		3.8		4.1		(.3)
Commercial		2.2		2.5		(.3)
Industrial		.2		.3		(.1)
Transportation and Other		2.3		2.0		.3
Total Regulated Gas Sales		8.5		8.9		(.4)

Regulated Gas Customers (in thousands)	2008	2007	Change
Residential	113	112		1
Commercial	9	10		(1)
Industrial	-	-		-
Transportation and Other	-	-		-
Total Regulated Gas Customers	122	122		-

Regulated Gas Revenue

Regulated Gas Revenue decreased by $10.0 million primarily due to (i) $6.3 million decrease due to Gas Cost Rate decreases effective April 2007 and November 2007, (ii) $3.7 million decrease due to warmer weather (a 7% decrease in Heating Degree Days), (iii) $2.2 million decrease due to differences in consumption among the various customer rate classes, partially offset by (iv) $2.2 million increase due to a base rate increase effective in April 2007.

Other Gas Revenue

Other Gas Revenue increased by $12.9 million primarily due to higher off-system sales (substantially offset in Gas Purchased expense).  The increase in gas sold off-system was due to (i) $7.5 million increase due to increased demand from electric generators and gas marketers during periods of available pipeline capacity driven by low demand for natural gas from regulated customers, resulting from warmer weather than 2007, and (ii) $4.8 million increase due to an increase in market prices.

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Operating Expenses

Fuel and Purchased Energy

Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply sales, decreased by $25.4 million to $195.4 million in 2008 from $220.8 million in 2007.  The decrease was primarily due to (i) $12.7 million decrease due to the sale of the Virginia distribution and default supply businesses on January 2, 2008, (ii) $10.2 million decrease due to differences in consumption among various customer rate classes, (iii) $7.0 million decrease due to lower weather-related sales, (iv) $2.2 million decrease in the Default Electricity Supply deferral balance, partially offset by (v) $6.7 million increase in average energy costs, the result of new annual Default Electricity Supply contracts.  Fuel and Purchased Energy expense is substantially offset by Default Supply Revenue.

Gas Purchased

Total Gas Purchased, which is primarily offset in Regulated Gas Revenue and Other Gas Revenue, increased by $1.6 million to $87.7 million in 2008 from $86.1 million in 2007.  The increase was primarily due to (i) $10.9 million increase in purchases for off-system sales, partially offset by (ii) $6.9 million decrease from the settlement of financial hedges (entered into as part of DPL’s regulated natural gas hedge program), and (iii) $3.8 million decrease in the deferred gas fuel balance.

Other Operation and Maintenance

Other Operation and Maintenance increased by $6.4 million to $56.0 million in 2008 from $49.6 million in 2007.  The increase was primarily due to the following: (i) $2.3 million increase in preventative maintenance and system operation costs, (ii) $1.7 million increase in costs associated with Default Electricity Supply (primarily deferred and recoverable), (iii) $.8 million increase due to higher bad debt expenses, and (iv) $.6 million increase in customer service operation expenses.

Gain on Sale of Assets

Gain on Sale of Assets increased $2.5 million to $3.1 million in 2008 from $.6 million in 2007.  The increase was primarily due to a $3.1 million gain on the sale of the Virginia distribution and default supply businesses.

Other Income (Expense)

Other Expenses (which are net of Other Income) decreased by $2.2 million to a net expense of $7.7 million in 2008 from a net expense of $9.9 million in 2007.  The decrease was primarily due to a decrease in interest on both short-term and long-term debt.

Income Tax Expense

DPL’s effective tax rates for the three months ended March 31, 2008 and 2007 were 33.2% and 41.4%, respectively.  The decrease in the effective tax rate in 2008 was primarily related to interest accrued on a tax claim filed with the IRS in March 2008.  The claim is for the treatment of casualty losses as current deductions (as opposed to being depreciated over their tax lives) on prior year returns currently under audit.

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Capital Requirements

Capital Expenditures

DPL’s capital expenditures for the three months ended March 31, 2008, totaled $32.0 million.  These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

In its Annual Report on Form 10-K for the year ended December 31, 2007, PHI projected the construction expenditures for its 230-mile, 500-kilovolt Mid-Atlantic Power Pathway Project (the MAPP Project) to be approximately $1 billion over a six-year period beginning in 2008.  This amount does not include the cost of significant 230 kilovolt support lines in Maryland and New Jersey to connect to the 500-kilovolt line, with an estimated cost of $200 million, and the additional cost of a direct current system underwater crossing of Chesapeake Bay, at an estimated cost of $375 million.  These enhancements have been recommended to PJM, and if approved, will increase PHI’s projected MAPP Project costs.

FORWARD-LOOKING STATEMENTS

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

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

· Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;

· Changes in and compliance with environmental and safety laws and policies;

· Weather conditions;

· Population growth rates and demographic patterns;

· Competition for retail and wholesale customers;

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· 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, PJM, the North American Electric Reliability Council and other applicable electric reliability organizations;

· Legal and administrative proceedings (whether civil or criminal) and settlements that influence DPL’s business and profitability;

· Volatility in market demand and prices for energy, capacity and fuel;

· Interest rate fluctuations and credit market concerns; and

· Effects of geopolitical events, including the threat of domestic terrorism.

Any forward-looking statements speak only as to the date of this Quarterly Report and DPL undertakes no obligation to 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 such factors, nor can DPL assess the impact of any such factor on DPL’s business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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

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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 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 the Federal Energy Regulatory Commission under PUHCA 2005.

DISCONTINUED OPERATIONS

On February 8, 2007, ACE completed the sale of the B.L. England generating facility.  B.L. England comprised a significant component of ACE’s generation operations and its sale required discontinued operations presentation under Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long Lived Assets,” on ACE’s Consolidated Statement of Earnings for the three months ended March 31, 2007.

The following table summarizes discontinued operations information for the three months ended March 31, 2007 (millions of dollars):

	2007
Operating Revenue	$9.7
Income Before Income Tax Expense	$  .2
Net Income	$  .1

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RESULTS OF OPERATIONS

The accompanying results of operations discussion is for the three months ended March 31, 2008, compared to the three months ended March 31, 2007.  Other than this disclosure, information under this item has been omitted in accordance with General Instruction H to the Form 10-Q.  All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2008		2007		Change
Regulated T&D Electric Revenue	$	74.6	$	72.0	$	2.6
Default Supply Revenue		282.6		261.5		21.1
Other Electric Revenue		4.3		4.7		(.4)
Total Operating Revenue	$	361.5	$	338.2	$	23.3

The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated Transmission and Distribution (T&D) Electric Revenue and Default Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the delivery of electricity, including the delivery of Default Electricity Supply, to ACE’s customers within its service territory at regulated rates.  Regulated T&D Electric Revenue also includes transmission service revenue that ACE receives as a transmission owner from PJM Interconnection, LLC (PJM).

Default Supply Revenue is the revenue received for Default Electricity Supply.  The costs related to Default Electricity Supply are included in Fuel and Purchased Energy expense.  Also included in Default Supply Revenue is revenue from transition bond charges and other restructuring related revenues.

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

In response to an order issued on January 18, 2008 by the New Jersey Board of Public Utilities (NJBPU) regarding changes to ACE’s retail transmission rates, ACE has established deferred accounting treatment for the difference between the rates that ACE is authorized to charge its customers for the transmission of default electricity supply and the cost that ACE incurs based on Federal Energy Regulatory Commission (FERC)-approved transmission formula rates.  Under the deferral arrangement, any over or under recovery is deferred pending an adjustment of retail rates in a future proceeding.

Effective January 1, 2008, ACE’s retail transmission revenue is being recorded as Default Supply Revenue, rather than as Regulated T&D Electric Revenue, thereby conforming to the practice of PHI’s other utility subsidiaries, which previously established deferred accounting treatment for any over or under recovery of retail transmission rates relative to the cost incurred based on FERC-approved transmission formula rates.  In addition, ACE’s retail transmission revenue for the period prior to January 1, 2008 has been reclassified to Default Supply Revenue in order to conform to current period presentation.

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Regulated T&D Electric

Regulated T&D Electric Revenue		2008		2007	Change
Residential	$	32.5	$	33.9	$	(1.4)
Commercial		21.6		22.0		(.4)
Industrial		3.3		3.1		.2
Other		17.2		13.0		4.2
Total Regulated T&D Electric Revenue	$	74.6	$	72.0	$	2.6

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2008	2007	Change
Residential	1,021	1,074		(53)
Commercial	1,029	1,014		15
Industrial	268	249		19
Other	13	13		-
Total Regulated T&D Electric Sales	2,331	2,350		(19)

Regulated T&D Electric Customers (in thousands)	2008		2007		Change
Residential		480		476		4
Commercial		63		63		-
Industrial		1		1		-
Other		1		1		-
Total Regulated T&D Electric Customers		545		541		4

Regulated T&D Electric Revenue increased by $2.6 million primarily due to the following: (i) $4.3 million increase in transmission service revenue primarily due to an increase in the FERC formula rate in June 2007, partially offset by (ii) $.9 million decrease due to differences in consumption among the various customer rate classes, and (iii) $.8 million decrease due to lower weather-related sales (a 6% decrease in Heating Degree Days).

Default Electricity Supply

Default Supply Revenue	2008		2007		Change
Residential	$	108.5	$	108.7	$	(.2)
Commercial		81.4		78.3		3.1
Industrial		11.2		10.9		.3
Other		81.5		63.6		17.9
Total Default Supply Revenue	$	282.6	$	261.5	$	21.1

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Other Default Supply Revenue consists primarily of revenue from the resale of energy and capacity under non-utility generating contracts between ACE and unaffiliated third parties (NUGs) in the PJM RTO market.

Default Electricity Supply Sales (GWh)	2008		2007		Change
Residential		1,021		1,074		(53)
Commercial		748		748		-
Industrial		68		86		(18)
Other		13		13		-
Total Default Electricity Supply Sales		1,850		1,921		(71)

Default Electricity Supply Customers (in thousands)	2008	2007	Change
Residential	480	476	4
Commercial	63	63	-
Industrial	1	1	-
Other	1	1	-
Total Default Electricity Supply Customers	545	541	4

Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy and Deferred Electric Service Costs, increased by $21.1 million primarily due to the following: (i) $18.3 million increase in wholesale energy revenues due to sale in PJM RTO at higher market prices of electricity purchased from NUGs, (ii) $10.3 million increase due to annual increases in market-based Default Electricity Supply rates, partially offset by (iii) $6.1 million decrease due to differences in consumption among the various customer rate classes, and (iv) $2.4 million decrease due to lower weather-related sales, (a 6% decrease in Heating Degree Days).

For the three months ended March 31, 2008 and 2007, ACE’s customers served energy by ACE represented 79% and 82% of ACE’s total sales, respectively.

Operating Expenses

Fuel and Purchased Energy

Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply sales, increased by $21.5 million to $245.3 million in 2008 from $223.8 million in 2007.  The increase was primarily due to the following: (i) $30.1 million increase due to new annual BGS supply contracts, partially offset by (ii) $5.3 million decrease primarily due to customers electing to purchase an increased amount of electricity from competitive suppliers, and (iii) $3.1 million decrease due to lower weather-related sales.  Fuel and Purchased Energy expense is substantially offset in Default Supply Revenue.

Other Operation and Maintenance

Other Operation and Maintenance increased by $6.5 million to $46.1 million in 2008 from $39.6 million in 2007.  The increase was primarily due to the following: (i) $3.4 million net increase primarily due to 2007 recovery of stranded costs, (ii) $1.5 million increase due to higher

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bad debt expenses (offset in Deferred Electric Service Costs), and (iii) $.6 million increase in customer service operation expenses.

Depreciation and Amortization

Depreciation and Amortization expenses increased by $7.0 million to $24.1 million in 2008 from $17.1 million in 2007.  The increase was primarily due to higher amortization related to a rate increase in October 2007 for Transition Bond Charge revenue (offset in Default Supply Revenue).

Deferred Electric Service Costs

Deferred Electric Service Costs decreased by $1.3 million to $24.7 million in 2008 from $26.0 million in 2007.  The decrease was primarily due to (i) $15.9 million net under-recovery associated with deferred energy costs, and (ii) $3.1 million net under-recovery associated with deferred transmission expenses, partially offset by (iii) $17.5 million net over-recovery associated with non-utility generation contracts between ACE and unaffiliated third parties.

Income Tax Expense

ACE’s effective tax rates for the three months ended March 31, 2008 and 2007 were (194.4)% and 35.8%, respectively.  The decrease in the effective tax rate in 2008 was primarily the result of depreciation method differences and interest accrued on a tax claim filed with the Internal Revenue Service in March 2008.  The claim is for the treatment of casualty losses as current deductions (as opposed to being depreciated over their tax lives) on prior year returns currently under audit.

Capital Requirements

Capital Expenditures

ACE's capital expenditures for the three months ended March 31, 2008, totaled $57.0 million.  These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

In its Annual Report on Form 10-K for the year ended December 31, 2007, PHI projected the construction expenditures for its 230-mile, 500-kilovolt Mid-Atlantic Power Pathway Project (the MAPP Project) to be approximately $1 billion over a six-year period beginning in 2008.  This amount does not include the cost of significant 230 kilovolt support lines in Maryland and New Jersey to connect to the 500-kilovolt line, with an estimated cost of $200 million, and the additional cost of a direct current system underwater crossing of Chesapeake Bay, at an estimated cost of $375 million.  These enhancements have been recommended to PJM, and if approved, will increase PHI’s projected MAPP Project costs.

FORWARD-LOOKING STATEMENTS

Some of the statements contained in this Quarterly Report on Form 10-Q are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding ACE’s intents, beliefs and current expectations. In some cases, you can identify forward-looking statements by terminology such as

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“may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. Any forward-looking statements are not guarantees of future performance, and actual results could differ materially from those indicated by the forward-looking statements. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause ACE’s actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements.

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

· Prevailing governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power expenses, and present or prospective wholesale and retail competition;

· Changes in and compliance with environmental and safety laws and policies;

· Weather conditions;

· Population growth rates and demographic patterns;

· Competition for retail and wholesale customers;

· General economic conditions, including potential negative impacts resulting from an economic downturn;

· Growth in demand, sales and capacity to fulfill demand;

· Changes in tax rates or policies or in rates of inflation;

· Changes in 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, PJM, the North American Electric Reliability Council and other applicable electric reliability organizations;

· 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;

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· Interest rate fluctuations and credit market concerns; and

· Effects of geopolitical events, including the threat of domestic terrorism.

Any forward-looking statements speak only as to the date of this Quarterly Report and ACE undertakes no obligation to 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 such factors, nor can ACE assess the impact of any such factor on ACE’s business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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

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Item 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

For information about PHI’s derivative activities, other than the information disclosed herein, refer to “Accounting For Derivatives” in Note 2 and “Use of Derivatives in Energy and Interest Rate Hedging Activities” in Note 13, and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” in the Consolidated Financial Statements of PHI included in its Annual Report on Form 10-K for the year ended December 31, 2007.

Pepco Holdings, Inc.

Commodity Price Risk

The Competitive Energy segments actively engage in commodity risk management activities to reduce their financial exposure to changes in the value of their assets and obligations due to commodity price fluctuations.  Certain of these risk management activities are conducted using instruments classified as derivatives under Statement of Financial Accounting Standards (SFAS) No. 133.  The Competitive Energy segments also manage commodity risk with contracts that are not classified as derivatives.  The Competitive Energy segments’ primary risk management objectives are (1) to manage the spread between the cost of fuel used to operate their electric 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 wholesale and retail sales commitments and the cost of supply used to service those commitments in order to ensure stable and known minimum cash flows and fix favorable prices and margins when they become available.

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 estimates VaR using a delta-normal 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 Three Months Ended March 31, 2008 (Millions of dollars)
	Proprietary Trading     VaR	VaR for Competitive Energy Activity (a)
95% confidence level, one-day    holding period, one-tailed
Period end	$-	$7.7
Average for the period	$-	$5.5
High	$-	$8.5
Low	$-	$3.9

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

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 default electricity supply contracts).

Conectiv Energy maintains a forward 36 month program with targeted ranges for economically hedging its projected plant output combined with its energy purchase commitments.  Beginning with the disclosure herein, Conectiv Energy is changing its disclosure to show the percentage of its entire expected plant output and energy purchase commitments for all hours that are hedged, as opposed to its hedged position with respect to its projected on-peak plant output and on-peak energy commitments, which previously was disclosed.  This change was made in recognition of the significant quantity of projected off-peak plant output and purchase commitments and due to the increased volatility of power prices during off-peak hours. Also beginning with the disclosure herein, Conectiv Energy is including default electricity supply contracts and associated hedges in ISONE.  The hedge percentages for all expected plant output and purchase commitment (based on the then current forward electricity price curve) are as follows:

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

The primary purpose of the risk management program is to improve the predictability and stability of margins by selling forward a portion of its projected plant output, and buying forward

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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 March 31, 2008, the electricity sold forward by Conectiv Energy as a percentage of projected plant output combined with energy purchase commitments was 107%, 106%, and 85% for the 1-12 month, 13-24 month and 25-36 month forward periods, respectively.  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 decreases in projected plant output since the forward sale commitments were entered into.  The amount of forward sales during the 1-12 month period represents 16% of Conectiv Energy’s combined total generating capability and energy purchase commitments.  The volumetric percentages for the forward periods can vary and may not represent the amount of expected value hedged.

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

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

Credit and Nonperformance Risk

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

Schedule of Credit Risk Exposure on Competitive Wholesale Energy Contracts (Millions of dollars)
	March 31, 2008
Rating (a)	Exposure Before Credit Collateral (b)	Credit Collateral (c)	Net Exposure	Number of Counterparties Greater Than 10% (d)	Net Exposure of Counterparties Greater Than 10%
Investment Grade	$383.4	$131.0	$252.4	-	-
Non-Investment Grade	50.2	8.9	41.3	-	-
No External Ratings	77.6	-	77.6	-	-
Credit reserves			1.3

(a)	Investment Grade - primarily determined using publicly available credit ratings of the counterparty.  If the counterparty has provided a guarantee by a higher-rated entity (e.g., its parent), it is determined based upon the rating of its guarantor.  Included in “Investment Grade” are counterparties with a minimum Standard & Poor’s or Moody’s Investor Service rating of BBB- or Baa3, respectively.
(b)	Exposure before credit collateral - includes the marked to market (MTM) energy contract net assets for open/unrealized transactions, the net receivable/payable for realized transactions and net open positions for contracts not subject to MTM.  Amounts due from counterparties are offset by liabilities payable to those counterparties to the extent that legally enforceable netting arrangements are in place.  Thus, this column presents the net credit exposure to counterparties after reflecting all allowable netting, but before considering collateral held.
(c)	Credit collateral - the face amount of cash deposits, letters of credit and performance bonds received from counterparties, not adjusted for probability of default, and, if applicable, property interests (including oil and gas reserves).
(d)	Using a percentage of the total exposure.

153

For additional information concerning market risk, please refer to Item 3, “Quantitative and Qualitative Disclosures about Market Risk -- Commodity Price Risk” and “Credit and Nonperformance Risk,” and for information regarding “Interest Rate Risk,” please refer to Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” in Pepco Holdings’ Annual Report on Form 10-K for the year ended December 31, 2007.

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

Item 4.  CONTROLS AND PROCEDURES

Pepco Holdings, Inc.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, Pepco Holdings has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of March 31, 2008 and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco Holdings have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to Pepco Holdings and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended (the Exchange Act) (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2008, 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.

Pepco Holdings converted to a new fixed asset system on January 1, 2008.  The new system provides enhanced jurisdictional asset and depreciation reporting; optimizes rate base and tax depreciation opportunities; and improves user and system efficiencies.

In addition, Pepco Holdings implemented an automated consolidation module to the Financial Reporting System on January 1, 2008.  This module automatically posts inter-company eliminations; allows for additional time to review and analyze consolidation results; and includes additional reporting and analytical capabilities.

154

Item 4T.  CONTROLS AND PROCEDURES

Potomac Electric Power Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, Pepco has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of March 31, 2008, and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to Pepco that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2008, 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.

Pepco converted to a new fixed asset system on January 1, 2008.  The new system provides enhanced jurisdictional asset and depreciation reporting; optimizes rate base and tax depreciation opportunities; and improves user and system efficiencies.

Delmarva Power & Light Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, DPL has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of March 31, 2008, and, based upon this evaluation, the chief executive officer and the chief financial officer of DPL have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to DPL that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2008, 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.

DPL converted to a new fixed asset system on January 1, 2008.  The new system provides enhanced jurisdictional asset and depreciation reporting; optimizes rate base and tax depreciation opportunities; and improves user and system efficiencies.

155

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 March 31, 2008, and, based upon this evaluation, the chief executive officer and the chief financial officer of ACE have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to ACE and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2008, 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.

ACE converted to a new fixed asset system on January 1, 2008.  The new system provides enhanced jurisdictional asset and depreciation reporting; optimizes rate base and tax depreciation opportunities; and improves user and system efficiencies.

Part II    OTHER INFORMATION

Item 1.   LEGAL PROCEEDINGS

Pepco Holdings

Other than ordinary routine litigation incidental to its and its subsidiaries’ business, PHI is not a party to, and its subsidiaries’ property is not subject to, any material pending legal proceedings except as described in Note (12), “Commitments and Contingencies--Legal Proceedings,” to the consolidated financial statements of PHI included herein.

Pepco

Other than ordinary routine litigation incidental to its business, Pepco is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (10), “Commitments and Contingencies--Legal Proceedings,” to the financial statements of Pepco included herein.

DPL

Other than ordinary routine litigation incidental to its business, DPL is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (10), “Commitments and Contingencies--Legal Proceedings,” to the financial statements of DPL included herein.

156

ACE

Other than ordinary routine litigation incidental to its business, ACE is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (10), “Commitments and Contingencies--Legal Proceedings,” to the financial statements of ACE included herein.

Item 1A.   RISK FACTORS

Pepco Holdings

For a discussion of Pepco Holdings’ risk factors, please refer to Item 1A “Risk Factors” in Pepco Holdings’ Annual Report on Form 10-K for the year ended December 31, 2007.  There have been no material changes to Pepco Holdings’ risk factors as disclosed in the 10-K.

Pepco

For a discussion of Pepco’s risk factors, please refer to Item 1A “Risk Factors” in Pepco’s Annual Report on Form 10-K for the year ended December 31, 2007.  There have been no material changes to Pepco’s risk factors as disclosed in the 10-K.

DPL

For a discussion of DPL’s risk factors, please refer to Item 1A “Risk Factors” in DPL’s Annual Report on Form 10-K for the year ended December 31, 2007.  There have been no material changes to DPL’s risk factors as disclosed in the 10-K.

ACE

For a discussion of ACE’s risk factors, please refer to Item 1A “Risk Factors” in ACE’s Annual Report on Form 10-K for the year ended December 31, 2007.  There have been no material changes to ACE’s risk factors as disclosed in the 10-K.

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

Pepco Holdings

None.

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

Item 3.    DEFAULTS UPON SENIOR SECURITIES

Pepco Holdings

None.

157

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

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

Pepco Holdings

None.

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

Item 5.    OTHER INFORMATION

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

158

Item 6.    EXHIBITS

The documents listed below are being filed or furnished on behalf of Pepco Holdings, Inc. (PHI), Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL), and Atlantic City Electric Company (ACE).

Exhibit   No.	Registrant(s)	Description of Exhibit	Reference
4	Pepco	Supplemental Indenture, dated as of March 24, 2008, with respect to Mortgage and Deed of Trust, dated July , 1936	Exh. 4.1 to Pepco’s Form 8-K, 3/28/08.
10.1	Pepco	Loan Agreement, dated as of May 1, 2008, between Potomac Electric Power Company and Wachovia Bank, National Association.	Exh. 10.1 to Pepco’s Form 8-K, 5/6/08.
10.2	Pepco	Loan Agreement, dated as of May 2, 2008, between Potomac Electric Power Company and Mizuho Corporate Bank (USA).	Exh. 10.2 to Pepco’s Form 8-K, 5/6/08.
12.1	PHI	Statements Re: Computation of Ratios	Filed herewith.
12.2	Pepco	Statements Re: Computation of Ratios	Filed herewith.
12.3	DPL	Statements Re: Computation of Ratios	Filed herewith.
12.4	ACE	Statements Re: Computation of Ratios	Filed herewith.
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.

159

Exhibit 12.1  Statements Re. Computation of Ratios

Pepco Holdings, Inc.

			For the Year Ended December 31,
	Three Months Ended  March 31, 2008			2007	2006		2005		2004		2003
	(Millions of dollars)
Income before extraordinary item (a)	$	101.3	$	324.1	$	245.0	$	368.5	$	257.4	$	204.9
Income tax expense (b)		52.6		187.9		161.4		255.2		167.3		62.1
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense		83.6		348.4		342.8		341.4		376.2		385.9
Other interest		6.2		25.4		18.8		20.3		20.6		21.7
Preferred dividend requirements     of subsidiaries		.1		.3		1.2		2.5		2.8		13.9
Total fixed charges		89.9		374.1		362.8		364.2		399.6		421.5
Non-utility capitalized interest		(1.0)		(1.6)		(1.0)		(.5)		(.1)		(10.2)
Income before extraordinary   item, income tax expense,   and fixed charges	$	242.8	$	884.5	$	768.2	$	987.4	$	824.2	$	678.3
Total fixed charges, shown above		89.9		374.1		362.8		364.2		399.6		421.5
Increase preferred stock dividend   requirements of subsidiaries to   a pre-tax amount		.1		.2		.8		1.7		1.8		4.2
Fixed charges for ratio   computation	$	90.0	$	374.3	$	363.6	$	365.9	$	401.4	$	425.7
Ratio of earnings to fixed charges   and preferred dividends		2.70		2.36		2.11		2.70		2.05		1.59

(a) Excludes income/losses from equity investments.

(b) Concurrent with the adoption of FIN 48 in 2007, amount includes interest on uncertain tax positions.

160

Exhibit 12.2  Statements Re. Computation of Ratios

Potomac Electric Power Company

			For the Year Ended December 31,
	Three Months Ended March 31, 2008			2007	2006		2005		2004		2003
	(Millions of dollars)
Net income	$	15.2	$	125.1	$	85.4	$	165.0	$	96.5	$	103.2
Income tax expense (a)		10.2		62.3		57.4		127.6		55.7		67.3
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense		24.1		86.5		77.1		82.8		82.5		83.8
Other interest		2.9		11.6		12.9		13.6		14.3		16.2
Preferred dividend requirements     of a subsidiary trust		-		-		-		-		-		4.6
Total fixed charges		27.0		98.1		90.0		96.4		96.8		104.6
Non-utility capitalized interest		-		-		-		-		-		-
Income before income tax expense,   and fixed charges	$	52.4	$	285.5	$	232.8	$	389.0	$	249.0	$	275.1
Ratio of earnings to fixed charges		1.94		2.91		2.59		4.04		2.57		2.63
Total fixed charges, shown above		27.0		98.1		90.0		96.4		96.8		104.6
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
Total fixed charges and   preferred dividends	$	27.0	$	98.1	$	91.7	$	98.7	$	98.4	$	110.1
Ratio of earnings to fixed charges   and preferred dividends		1.94		2.91		2.54		3.94		2.53		2.50

(a)           Concurrent with the adoption of FIN 48 in 2007, amount includes interest on uncertain tax positions.

161

Exhibit 12.3  Statements Re. Computation of Ratios

Delmarva Power & Light Company

			For the Year Ended December 31,
	Three Months Ended March 31, 2008			2007	2006		2005		2004		2003
	(Millions of dollars)
Net income	$	26.1	$	44.9	$	42.5	$	74.7	$	63.0	$	52.4
Income tax expense (a)		13.0		37.2		32.1		57.6		48.1		37.0
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense		9.7		43.8		41.3		35.3		33.0		37.2
Other interest		.6		2.3		2.5		2.7		2.2		2.7
Preferred dividend requirements     of a subsidiary trust		-		-		-		-		-		2.8
Total fixed charges		10.3		46.1		43.8		38.0		35.2		42.7
Income before income tax expense,   and fixed charges	$	49.4	$	128.2	$	118.4	$	170.3	$	146.3	$	132.1
Ratio of earnings to fixed charges		4.80		2.78		2.70		4.48		4.16		3.09
Total fixed charges, shown above		10.3		46.1		43.8		38.0		35.2		42.7
Preferred dividend requirements,   adjusted to a pre-tax amount		-		-		1.4		1.8		1.7		1.7
Total fixed charges and   preferred dividends	$	10.3	$	46.1	$	45.2	$	39.8	$	36.9	$	44.4
Ratio of earnings to fixed charges   and preferred dividends		4.80		2.78		2.62		4.28		3.96		2.98

(a)           Concurrent with the adoption of FIN 48 in 2007, amount includes interest on uncertain tax positions.

162

Exhibit 12.4 Statements Re. Computation of Ratios

Atlantic City Electric Company

			For the Year Ended December 31,
	Three Months Ended March 31, 2008			2007	2006		2005		2004		2003
	(Millions of dollars)
Income from continuing operations	$	5.3	$	60.0	$	60.1	$	51.1	$	58.8	$	31.6
Income tax (benefit) expense (a)		(3.5)		40.9		33.0		41.2		40.7		20.7
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense		16.0		66.0		64.9		60.1		62.2		63.7
Other interest		.8		3.3		3.2		3.7		3.4		2.6
Preferred dividend requirements     of subsidiary trusts		-		-		-		-		-		1.8
Total fixed charges		16.8		69.3		68.1		63.8		65.6		68.1
Income before extraordinary   item, income tax expense,   and fixed charges	$	18.6	$	170.2	$	161.2	$	156.1	$	165.1	$	120.4
Ratio of earnings to fixed charges		1.11		2.46		2.37		2.45		2.52		1.77
Total fixed charges, shown above		16.8		69.3		68.1		63.8		65.6		68.1
Preferred dividend requirements   adjusted to a pre-tax amount		-		.5		.5		.5		.5		.5
Total fixed charges and   preferred dividends	$	16.8	$	69.8	$	68.6	$	64.3	$	66.1	$	68.6
Ratio of earnings to fixed charges   and preferred dividends		1.11		2.44		2.35		2.43		2.50		1.76

(a)           Concurrent with the adoption of FIN 48 in 2007, amount includes interest on uncertain tax positions.

163

Exhibit 31.1

CERTIFICATION

I Dennis R. Wraase, certify that:

1. I have reviewed this report on Form 10-Q of Pepco Holdings, Inc.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (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:  May 8, 2008   /s/  D. R. WRAASE Dennis R. Wraase Chairman of the Board and    Chief Executive Officer

164

Exhibit 31.2

CERTIFICATION

I, Paul H. Barry, certify that:

1. I have reviewed this report on Form 10-Q of Pepco Holdings, Inc.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 2008   /s/ P. H. BARRY Paul H. Barry Senior Vice President and     Chief Financial Officer

165

Exhibit 31.3

CERTIFICATION

I, Joseph M. Rigby, certify that:

1. I have reviewed this report on Form 10-Q of Potomac Electric Power Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 2008   /s/ J. M. RIGBY Joseph M. Rigby President and Chief Executive Officer

166

Exhibit 31.4

CERTIFICATION

I, Paul H. Barry, certify that:

1. I have reviewed this report on Form 10-Q of Potomac Electric Power Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 2008   /s/ P. H. BARRY Paul H. Barry Senior Vice President and     Chief Financial Officer

167

Exhibit 31.5

CERTIFICATION

I, Joseph M. Rigby, certify that:

1. I have reviewed this report on Form 10-Q of Delmarva Power & Light Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 2008   /s/ J. M. RIGBY Joseph M. Rigby President and Chief Executive Officer

168

Exhibit 31.6

CERTIFICATION

I, Paul H. Barry, certify that:

1. I have reviewed this report on Form 10-Q of Delmarva Power & Light Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 2008   /s/ P. H. BARRY Paul H. Barry Senior Vice President and     Chief Financial Officer

169

Exhibit 31.7

CERTIFICATION

I, Joseph M. Rigby, certify that:

1. I have reviewed this report on Form 10-Q of Atlantic City Electric Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 2008   /s/ J. M. RIGBY Joseph M. Rigby President and Chief Executive Officer

170

Exhibit 31.8

CERTIFICATION

I, Paul H. Barry, certify that:

1. I have reviewed this report on Form 10-Q of Atlantic City Electric Company.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 2008   /s/ P. H. BARRY Paul H. Barry Chief Financial Officer

171

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, Paul H. Barry, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Pepco Holdings, Inc. for the quarter ended March 31, 2008, 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.

May 8, 2008   /s/ D. R. WRAASE Dennis R. Wraase Chairman of the Board and    Chief Executive Officer

May 8, 2008   /s/ P. H. BARRY Paul H. Barry 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.

172

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, Joseph M. Rigby, and I, Paul H. Barry, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Potomac Electric Power Company for the quarter ended March 31, 2008, 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.

May 8, 2008   /s/ J. M. RIGBY Joseph M. Rigby President and Chief Executive Officer

May 8, 2008   /s/ P. H. BARRY Paul H. Barry 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.

173

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, Joseph M. Rigby, and I, Paul H. Barry, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Delmarva Power & Light Company for the quarter ended March 31, 2008, 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.

May 8, 2008   /s/ J. M. RIGBY Joseph M. Rigby President and Chief Executive Officer

May 8, 2008   /s/ P. H. BARRY Paul H. Barry 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.

174

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, Joseph M. Rigby, and I, Paul H. Barry, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Atlantic City Electric Company for the quarter ended March 31, 2008, 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.

May 8, 2008   /s/ J. M. RIGBY Joseph M. Rigby President and Chief Executive Officer

May 8, 2008   /s/ P. H. BARRY Paul H. Barry 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.

175

SIGNATURES

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

	PEPCO HOLDINGS, INC. (PHI) POTOMAC ELECTRIC POWER COMPANY (Pepco) DELMARVA POWER & LIGHT COMPANY (DPL) ATLANTIC CITY ELECTRIC COMPANY (ACE)        (Registrants)
May 8, 2008	By   /s/ P. H. BARRY                              Paul H. Barry         Senior Vice President and         Chief Financial Officer,             PHI, Pepco and DPL         Chief Financial Officer, ACE

176

INDEX TO EXHIBITS FILED HEREWITH
Exhibit No.	Registrant(s)	Description of Exhibit
12.1	PHI	Statements Re: Computation of Ratios
12.2	Pepco	Statements Re: Computation of Ratios
12.3	DPL	Statements Re: Computation of Ratios
12.4	ACE	Statements Re: Computation of Ratios
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer

INDEX TO EXHIBITS FURNISHED HEREWITH
Exhibit No.	Registrant(s)	Description of Exhibit
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350

177