phi2008q3.htm

10-Q 1 phi2008q3.htm QUARTERLY REPORT ON FORM 10-Q phi2008q3.htm

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 September 30, 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 September 30, 2008
Pepco Holdings	202,208,790	($.01 par value)
Pepco	100	($.01 par value) (a)
DPL	1,000	($2.25 par value) (b)
ACE	8,546,017	($3.00 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	118
Item 3.	-	Quantitative and Qualitative Disclosures About Market Risk	199
Item 4.	-	Controls and Procedures	202
Item 4T.	-	Controls and Procedures	202
PART II	OTHER INFORMATION
Item 1.	-	Legal Proceedings	204
Item 1A.	-	Risk Factors	204
Item 2.	-	Unregistered Sales of Equity Securities and Use of Proceeds	209
Item 3.	-	Defaults Upon Senior Securities	210
Item 4.	-	Submission of Matters to a Vote of Security Holders	210
Item 5.	-	Other Information	210
Item 6.	-	Exhibits	211
Signatures			228

TABLE OF CONTENTS – EXHIBITS
Exh. No.	Registrant(s)	Description of Exhibit	Page
12.1	PHI	Statements Re: Computation of Ratios	212
12.2	Pepco	Statements Re: Computation of Ratios	213
12.3	DPL	Statements Re: Computation of Ratios	214
12.4	ACE	Statements Re: Computation of Ratios	215
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	216
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	217
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	218
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	219
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	220
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	221
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	222
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	223
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	224
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	225
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	226
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	227

GLOSSARY OF TERMS

Term	Definition
2007 Maryland Rate Orders	The MPSC orders approving new electric service distribution base rates for Pepco and DPL in Maryland, each effective June 16, 2007
A&N	A&N Electric Cooperative, purchaser of DPL’s retail electric distribution business in Virginia
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
ADITC	Accumulated deferred investment tax credits
Ancillary services	Generally, electricity generation reserves and reliability services
AOCI	Accumulated Other Comprehensive Income
APB	Accounting Principles Board
APIC	Additional paid-in capital
Appeals Office	U.S. Office of Appeals of the IRS
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 mechanism
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
EDIT	Excess Deferred Income Taxes
EITF	Emerging Issues Task Force
EPA	U.S. Environmental Protection Agency
EPS	Earnings per share
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
FIN	FASB Interpretation Number
FSP	FASB Staff Position

Term	Definition
GAAP	Accounting principles generally accepted in the United States of America
GAAP hierarchy	The sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP
GCR	Gas cost rate, a mechanism used in Delaware that permits DPL to recover gas procurement costs through customer rates
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
LTIP	Pepco Holdings’ Long-Term Incentive Plan
MAPP Project	Mid-Atlantic Power Pathway Project
Mirant	Mirant Corporation
MPSC	Maryland Public Service Commission
MFVRD	Modified fixed variable rate design
New Jersey Societal Benefit Charge	Revenue ACE receives to recover certain costs incurred under various NJBPU-mandated social programs
NFA	No Further Action letter issued by the NJDEP
NJBPU	New Jersey Board of Public Utilities
NJDEP	New Jersey Department of Environmental Protection
Normalization provisions	Sections of the 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
OCI	Other Comprehensive Income
ODEC	Old Dominion Electric Cooperative, purchaser of DPL’s wholesale transmission business in Virginia
OPC	District of Columbia Office of People’s Counsel
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

Term	Definition
PJM RTO	PJM Regional Transmission Organization
Power Delivery	PHI’s Power Delivery Business
PPA	Power Purchase Agreement
PRP	Potentially responsible party
PUHCA 2005	Public Utility Holding Company Act of 2005
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 MPSC-approved revenue based on the distribution charge per customer in the 2007 Maryland Rate Orders
ROE	Return on equity
SBC	Societal Benefits Charge in New Jersey
SBPA	Standby Bond Purchase Agreement
SEC	Securities and Exchange Commission
Sempra	Sempra Energy Trading LLC
SFAS	Statement of Financial Accounting Standards
SILO	Sale-in/lease-out
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 market	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
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
Transition Bond Charge	Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees
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

iii

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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	53	76	98
Consolidated Statements of Comprehensive Earnings	4	N/A	N/A	N/A
Consolidated Balance Sheets	5	54	77	99
Consolidated Statements of Cash Flows	7	56	79	101
Notes to Consolidated Financial Statements	8	57	80	102

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

THIS PAGE INTENTIONALLY LEFT BLANK.

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
		2008		2007		2008		2007
	(In millions, except per share data)
Operating Revenue
Power Delivery	$	1,667.6	$	1,596.3	$	4,259.3	$	4,033.7
Competitive Energy		1,379.1		1,155.8		4,036.2		2,947.0
Other		12.8		18.2		(76.9)		52.7
Total Operating Revenue		3,059.5		2,770.3		8,218.6		7,033.4

Operating Expenses
Fuel and purchased energy		2,123.5		1,890.7		5,773.6		4,780.1
Other services cost of sales		208.6		160.5		568.5		433.2
Other operation and maintenance		241.8		214.3		691.4		632.2
Depreciation and amortization		99.3		87.6		282.9		273.4
Other taxes		98.8		100.0		272.4		271.5
Deferred electric service costs		12.0		29.1		20.0		47.2
Impairment loss		.7		-		.7		1.6
Effect of settlement of Mirant bankruptcy claims		-		(33.4)		-		(33.4)
Loss (gain) on sale of assets		-		.7		(3.1)		(1.8)
Total Operating Expenses		2,784.7		2,449.5		7,606.4		6,404.0

Operating Income		274.8		320.8		612.2		629.4

Other Income (Expenses)
Interest and dividend income		3.9		4.9		16.1		11.7
Interest expense		(81.3)		(86.2)		(242.4)		(254.6)
(Loss) income from equity investments		(1.5)		3.1		(3.5)		10.2
Other income		4.3		5.8		14.1		21.2
Other expenses		(1.3)		(.5)		(2.5)		(.9)
Total Other Expenses		(75.9)		(72.9)		(218.2)		(212.4)

Preferred Stock Dividend Requirements of Subsidiaries		.1		.1		.2		.3

Income Before Income Tax Expense		198.8		247.8		393.8		416.7

Income Tax Expense		80.0		80.2		160.8		140.3

Net Income		118.8		167.6		233.0		276.4

Retained Earnings at Beginning of Period		1,198.2		1,069.6		1,192.7		1,068.7

Cumulative Effect Adjustment Related to the Implementation of FIN 48		-		-		-		(7.4)

LTIP Dividend		-		(.1)		(.2)		(.3)

Dividends Paid on Common Stock (Note (13))		(54.5)		(50.2)		(163.0)		(150.5)

Retained Earnings at End of Period	$	1,262.5	$	1,186.9	$	1,262.5	$	1,186.9

Basic and Diluted Share Information
Weighted average shares outstanding		201.8		193.5		201.4		193.1
Earnings per share of common stock	$	.59	$	.87	$	1.16	$	1.43

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

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
		2008		2007		2008		2007
		(Millions of dollars)

Net income	$	118.8	$	167.6	$	233.0	$	276.4

Other comprehensive (losses) earnings

Unrealized (losses) gains on commodity derivatives designated as cash flow hedges:
Unrealized holding losses arising during period		(671.9)		(79.9)		(43.5)		(59.6)
Less: reclassification adjustment for gains (losses) included in net earnings		14.2		(50.7)		85.7		(63.2)
Net unrealized (losses) gains on commodity derivatives		(686.1)		(29.2)		(129.2)		3.6

Realized gains on Treasury lock transactions		1.4		1.8		4.1		8.0

Amortization of gains and losses for prior service costs		.2		(.6)		(4.8)		(.6)

Other comprehensive (losses) earnings, before income taxes		(684.5)		(28.0)		(129.9)		11.0

Income tax (benefit) expense		(278.2)		(9.7)		(51.7)		5.3

Other comprehensive (losses) earnings, net of income taxes		(406.3)		(18.3)		(78.2)		5.7

Comprehensive (losses) earnings	$	(287.5)	$	149.3	$	154.8	$	282.1

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

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

ASSETS		September 30, 2008		December 31, 2007
	(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$	227.2	$	55.1
Restricted cash equivalents			45.4		14.5
Accounts receivable, less allowance for uncollectible accounts of $36.4 million and $30.6 million, respectively			1,448.5		1,278.3
Fuel, materials and supplies-at average cost			359.7		287.9
Unrealized gains - derivative contracts			106.6		43.0
Prepayments of income taxes			210.1		249.8
Prepaid expenses and other			129.6		68.5
Total Current Assets			2,527.1		1,997.1

INVESTMENTS AND OTHER ASSETS
Goodwill			1,409.0		1,409.6
Regulatory assets			1,552.6		1,515.7
Investment in finance leases held in trust			1,321.2		1,384.4
Income taxes receivable			200.7		196.1
Restricted cash equivalents			104.8		424.1
Other			290.1		307.3
Total Investments and Other Assets			4,878.4		5,237.2

PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			12,731.2		12,306.5
Accumulated depreciation			(4,564.1)		(4,429.8)
Net Property, Plant and Equipment			8,167.1		7,876.7

TOTAL ASSETS		$	15,572.6	$	15,111.0

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

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


LIABILITIES AND SHAREHOLDERS’ EQUITY		September 30, 2008		December 31, 2007
	(Millions of dollars, except shares)

CURRENT LIABILITIES
Short-term debt		$	879.9	$	288.8
Current maturities of long-term debt and project funding			226.2		332.2
Accounts payable and accrued liabilities			867.5		796.7
Capital lease obligations due within one year			6.2		6.0
Taxes accrued			131.1		133.5
Interest accrued			80.4		70.1
Liabilities and accrued interest related to uncertain tax positions			80.4		131.7
Other			361.9		277.8
Total Current Liabilities			2,633.6		2,036.8

DEFERRED CREDITS
Regulatory liabilities			937.4		1,248.9
Deferred income taxes, net			2,084.8		2,105.1
Investment tax credits			35.7		38.9
Pension benefit obligation			153.4		65.5
Other postretirement benefit obligations			427.1		385.5
Income taxes payable			172.3		164.9
Liabilities and accrued interest related to uncertain tax positions			186.3		65.1
Other			239.9		241.1
Total Deferred Credits			4,236.9		4,315.0

LONG-TERM LIABILITIES
Long-term debt			4,110.1		4,174.8
Transition Bonds issued by ACE Funding			411.0		433.5
Long-term project funding			19.3		20.9
Capital lease obligations			102.2		105.4
Total Long-Term Liabilities			4,642.6		4,734.6

COMMITMENTS AND CONTINGENCIES (NOTE (13))

MINORITY INTEREST			6.2		6.2

SHAREHOLDERS’ EQUITY
Common stock, $.01 par value, authorized 400,000,000 shares, 202,208,790 shares and 200,512,890 shares outstanding, respectively			2.0		2.0
Premium on stock and other capital contributions			2,912.5		2,869.2
Accumulated other comprehensive loss			(123.7)		(45.5)
Retained earnings			1,262.5		1,192.7
Total Shareholders’ Equity			4,053.3		4,018.4

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$	15,572.6	$	15,111.0

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

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
		2008		2007
	(Millions of dollars)
OPERATING ACTIVITIES
Net income	$	233.0	$	276.4
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		282.9		273.4
Effect of settlement of Mirant bankruptcy claims		-		(33.4)
Gain on sale of assets		(3.1)		(1.8)
Loss (gain) on sale of other investment		.6		(.7)
Impairment loss		.7		1.6
Rents received from cross-border energy leases under income earned		(51.3)		(57.5)
Non-cash charge to reduce equity value of PHI’s cross-border energy lease investments		124.4		-
Proceeds from settlement of Mirant bankruptcy claims		-		507.2
Reimbursements to Mirant		-		(108.3)
Changes in restricted cash equivalents related to Mirant settlement		316.9		(416.7)
Deferred income taxes		30.9		112.9
Pension and other postretirement benefit obligations		20.8		23.6
Net unrealized (gains) losses on commodity derivatives accounted for at fair value		(26.8)		1.6
Allowance for equity funds used during construction		(3.7)		(3.4)
Investment tax credit adjustments		(3.2)		(3.5)
Changes in:
Accounts receivable		(129.9)		(234.2)
Regulatory assets and liabilities		(284.3)		17.9
Fuel, materials and supplies		(72.1)		(19.3)
Accounts payable and accrued liabilities		86.6		77.4
Interest and taxes accrued		70.0		(22.2)
Cash collateral related to derivative activities		(88.0)		34.4
Prepaid expenses		(36.6)		(.4)
Proceeds from sale of B.L. England emission allowances		-		25.3
Other changes in working capital		.2		6.4
Net other operating		.8		5.8
Net Cash From Operating Activities		468.8		462.5

INVESTING ACTIVITIES
Net investment in property, plant and equipment		(560.6)		(422.7)
Proceeds from settlement of Mirant bankruptcy claims representing reimbursement for investment in property, plant and equipment		-		15.0
Proceeds from sale of assets		51.5		10.6
Proceeds from the sale of other investments		-		1.2
Changes in restricted cash equivalents		(30.9)		4.9
Net other investing activities		2.2		(.8)
Net Cash Used By Investing Activities		(537.8)		(391.8)

FINANCING ACTIVITIES
Dividends paid on common stock		(163.0)		(150.5)
Dividends paid on preferred stock		(.2)		(.3)
Common stock issued for the Dividend Reinvestment Plan		24.8		21.0
Issuance of common stock		14.8		23.9
Redemption of preferred stock of subsidiaries		-		(18.2)
Issuances of long-term debt		400.0		452.8
Reacquisition of long-term debt		(437.8)		(670.8)
Issuances of short-term debt and borrowings against credit facility, net		441.1		246.6
Cost of issuances		(12.8)		(3.0)
Net other financing activities		(25.8)		5.0
Net Cash From (Used By) Financing Activities		241.1		(93.5)

Net Increase (Decrease) in Cash and Cash Equivalents		172.1		(22.8)
Cash and Cash Equivalents at Beginning of Period		55.1		48.8

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	227.2	$	26.0

NON-CASH ACTIVITIES
Asset retirement obligations associated with removal costs transferred to regulatory liabilities	$	5.2	$	8.6
Recoverable pension/OPEB costs included in regulatory assets		90.1		(12.1)
Conversion of DPL long-term debt to short-term debt		150.0		-

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid (received) for income taxes	$	83.3	$	(5.8)

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

PEPCO HOLDINGS

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PEPCO HOLDINGS, INC.

(1) ORGANIZATION

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

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

Each company is responsible for the delivery of electricity and, in the case of DPL, natural gas in its service territory, for which it is paid tariff rates established by the 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 lease investments, with a book value at September 30, 2008 of approximately $1.3 billion. This activity constitutes a fourth operating segment, which is designated as “Other Non-Regulated” for financial reporting purposes. For a discussion of PHI’s cross-border energy lease investments, see “Change in Accounting Estimate” in Note (2), “Leasing Activities” in Note (5), “Income Taxes” in Note (9) and “Commitments and Contingencies — Regulatory and Other Matters — PHI’s Cross-Border Energy Lease Investments,” in Note (13).

Impact of the Current Capital and Credit Market Disruptions

The recent disruptions in the capital and credit markets, combined with the volatility of energy prices, have had an impact on several aspects of PHI’s businesses. While these conditions have required PHI and its subsidiaries to make certain adjustments in their financial management activities, PHI believes that it and its subsidiaries currently have sufficient liquidity to fund their operations and meet their financial obligations. These market conditions, should they continue, however, could have a negative effect on PHI’s financial condition, results of operations and cash flows.

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Liquidity Requirements

PHI and its subsidiaries depend on access to the capital and credit markets to meet their liquidity and capital requirements. To meet their liquidity requirements, PHI’s utility subsidiaries and its Competitive Energy businesses historically have relied on the issuance of commercial paper and short-term notes and on bank lines of credit to supplement internally generated cash from operations. PHI’s primary credit source is its $1.5 billion syndicated credit facility, which can be used by PHI and its utility subsidiaries to borrow funds, obtain letters of credit and support the issuance of commercial paper. This facility is in effect until May 2012 and consists of commitments from 17 lenders, no one of which is responsible for more than 8.5% of the total $1.5 billion commitment. The terms and conditions of the facility are also discussed below in Note (8).

Due to the capital and credit market disruptions, the market for commercial paper in September and October 2008 has been severely restricted for most companies. As a result, PHI and its subsidiaries have not been able to issue commercial paper on a day-to-day basis either in amounts or with maturities that they have typically required for cash management purposes. Given their restricted access to the commercial paper market and the uncertainty in the credit markets generally, PHI and each of its utility subsidiaries in September and early October borrowed under the credit facility to create a cash reserve for future short-term operating needs, as discussed below in Note (8).

At September 30, 2008, the amount of cash, plus the amount of credit under the credit facility, available to meet the liquidity needs of PHI on a consolidated basis totaled $787 million, of which $308 million consisted of the combined cash and borrowing capacity of PHI’s utility subsidiaries. During the month of October 2008, the average daily amount of the combined cash and borrowing capacity of PHI on a consolidated basis was $601 million, and for its utility subsidiaries was $286 million. This decrease in liquidity of PHI on a consolidated basis was primarily due to a significant decline in energy prices in October, which caused an increase in the collateral obligations of the Competitive Energy businesses. In addition, during the month of October 2008, PHI’s consolidated cash and borrowing capacity ranged from a low of $380 million to a high of $847 million. The utility subsidiaries’ cash and borrowing capacity ranged from a low of $178 million to a high of $350 million.

To address the challenges posed by the current capital and credit market environment and to ensure that PHI and its subsidiaries will continue to have sufficient access to cash to meet their liquidity needs, PHI and its subsidiaries have undertaken or have under review a number of actions, including the following:

PHI has conducted a review to identify cash and liquidity conservation measures, including opportunities to reduce collateral obligations and to defer capital expenditures. Several measures to reduce collateral obligations and expenditures have been taken. Additional measures could be undertaken if conditions warrant.

·	PHI is actively exploring a broad range of financing alternatives, including equity and debt offerings, bank loan facilities and letter of credit facilities.

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Due to the financial market conditions, which have caused uncertainty of short-term funding, each of PHI's utility subsidiaries has sought regulatory authority to raise additional capital to fund utility construction and operations. In this regard:

ACE has obtained approval from the New Jersey Board of Public Utilities to issue up to $250 million in long-term debt securities no later than December 31, 2008. The proceeds can be used to refund short-term debt incurred to finance utility construction and operations on a temporary basis and incurred to fund the temporary repurchase of tax-exempt auction rate securities.

·	Pepco and DPL have filed similar applications with their respective public service commissions, which are currently pending.

Collateral Requirements of the Competitive Energy Businesses

In conducting its retail energy sales business, Pepco Energy Services typically enters into electricity and natural gas sales contracts under which it is committed to supply the electricity or natural gas requirements of its retail customers over a specified period at agreed upon prices. Generally, Pepco Energy Services acquires the energy to serve this load by entering into wholesale purchase contracts. To protect the respective parties against the risk of nonperformance by the other party, these wholesale purchase contracts typically impose collateral requirements that are tied to changes in the price of the contract commodity. In periods of energy market price volatility, these collateral obligations can fluctuate materially on a day-to-day basis.

Pepco Energy Services’ practice of offsetting its energy sale obligations with corresponding purchases of energy has the effect of substantially reducing the exposure its margins have to energy price fluctuations. In addition, the non-performance risks associated with its retail energy sales are relatively low due to its government customers, coupled with the purchase of insurance on a significant portion of its commercial and other accounts receivable. However, because its energy sales contracts typically do not have collateral obligations, during periods of declining energy prices Pepco Energy Services is exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its customers. Over the past several months, the decrease in energy prices has caused an increase in the collateral obligations of Pepco Energy Services.

In addition, Conectiv Energy and Pepco Energy Services (aside from its retail energy sales business) each enter into various contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce its financial exposure to changes in the value of its assets and obligations due to energy price fluctuations. These contracts also typically have collateral requirements.

Depending on the contract terms, the collateral required to be posted by Pepco Energy Services and Conectiv Energy can be of varying forms, including cash, letters of credit and guarantees. Over the preceding nine months, the combined net cash collateral position of the Pepco Energy Services and Conectiv Energy businesses was:

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·	net cash collateral posted of $90.3 million on December 31, 2007,

·	net cash collateral held of $3.6 million on March 31, 2008,

·	net cash collateral held of $237.1 million on June 30, 2008, and

·	net cash collateral posted of $193.1 million on September 30, 2008.

During the month of October 2008, the average daily net cash collateral position of the Pepco Energy Services and Conectiv Energy businesses combined was net cash collateral posted in the amount of approximately $243 million.

Ongoing Monitoring of Financial and Market Conditions

PHI monitors its liquidity position on a daily basis and routinely conducts stress testing to assess the impact of changes in commodity prices on its collateral requirements. PHI also closely monitors its credit ratings and outlooks and those of its rated subsidiaries, and computes the hypothetical effect of changes in credit ratings on collateral requirements and the cost of capital. Based on contractual provisions in effect at September 30, 2008, a one-level downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries, which would decrease PHI’s rating to below “investment grade,” would increase the collateral obligation of PHI and its subsidiaries by up to $403 million.

Counterparty Credit Risk

PHI is exposed to the risk that the counterparties to contracts may fail to meet their contractual payment obligations or may fail to deliver purchased commodities or services at the contracted price. PHI attempts to minimize these risks through, among other things, formal credit policies, regular assessments of counterparty creditworthiness, and the establishment of a credit limit for each counterparty.

Pension and Postretirement Benefit Plans

(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

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read in conjunction 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 financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly Pepco Holdings’ financial condition as of September 30, 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 and nine months ended September 30, 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.

Change in Accounting Estimate

As further discussed in “Leasing Activities” in Note (5), “Income Taxes” in Note (9) and “Commitments and Contingencies — Regulatory and Other Matters — PHI’s Cross-Border Energy Lease Investments,” in Note (13), PHI maintains a portfolio of cross-border energy sale-leaseback investments. The book equity value of such cross-border energy lease investments and the pattern of recognizing the related cross-border energy lease income are based on the timing and amount of all cash flows related to the cross-border energy lease investments, including income tax-related cash flows. These investments are more commonly referred to as sale-in/lease-out (SILO) transactions. PHI currently derives tax benefits from these investments based on the extent to which rental income is exceeded by depreciation deductions on the purchase price of the assets and interest deductions on the non-recourse debt financing (obtained to fund a substantial portion of the purchase price of the assets). The Internal Revenue Service (IRS) has announced broadly its intention to disallow the tax benefits recognized by all taxpayers on these investments, and, more specifically, the IRS has disallowed interest and depreciation deductions claimed by PHI related to these investments on the 2001 and 2002 PHI federal income tax returns currently under audit and has sought to recharacterize the leases as loan transactions as to which PHI would be subject to original issue discount income.

During the second quarter of 2008, decisions in favor of the IRS regarding disallowed deductions were reached in several court cases involving other taxpayers with certain cross-border energy lease investments. Under Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), the financial statement recognition of an uncertain tax position is permitted only if it is more likely than not that the position will be sustained. Further, under FASB Staff Position (FSP) No. 13-2, “Accounting for a Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged-Lease Transaction” (FSP 13-2), a company is required to assess on a periodic basis the likely outcome of tax positions relating to its cross-border energy lease investments and, if there is a change or a projected change in the estimated timing of the tax benefits generated from these investments, a recalculation of the value of its equity investment is required.

While PHI believes that its tax position with regard to its cross-border energy lease investments is appropriate based on applicable statutes, regulations and case law and intends to contest the adjustments proposed by the IRS, after evaluating the recent court rulings described above, PHI, at June 30, 2008, reassessed the sustainability of its tax position and revised its assumptions regarding the estimated timing of the tax benefits generated from its cross-border energy lease investments. Based on this reassessment, for the

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quarter ended June 30, 2008, PHI recorded an after-tax charge to net income of $92.9 million, consisting of the following components:

·	A non-cash pre-tax charge of $124.4 million ($86.0 million after tax) under FSP 13-2 to reduce the equity value of these cross-border energy lease investments. This pre-tax charge was recorded in the Consolidated Statement of Earnings as a reduction in other operating revenue.

A non-cash after-tax charge of $6.9 million to reflect the anticipated additional interest expense under FIN 48 related to estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed (January 1, 2001 through June 30, 2008). This after-tax charge was recorded in the Consolidated Statement of Earnings as an increase in income tax expense.

The charge pursuant to FSP 13-2 reflected changes to the book equity value of the cross-border energy lease investments and the pattern of recognizing the related cross-border energy lease income. This amount is being recognized as income over the remaining term of the affected leases, which expire between 2017 and 2047. The tax benefits associated with the lease transactions represent timing differences that do not change the aggregate amount of lease net income over the life of the transactions. No additional charges were considered necessary in the third quarter of 2008.

FIN 46R, “Consolidation of Variable Interest Entities”

Pepco Holdings, through its ACE subsidiary, has power purchase agreements (PPAs) with a number of entities including three contracts between unaffiliated non-utility generators (NUGs). Due to a variable element in the pricing structure of the NUGs, Pepco Holdings potentially assumes the variability in the operations of the plants related to these PPAs, and therefore, has a variable interest in the entities. In accordance with the provisions of FIN 46R (revised December 2003), entitled “Consolidation of Variable Interest Entities” (FIN 46R) and 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 third 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 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 power purchase activities with the counterparties to the NUGs for the three months ended September 30, 2008 and 2007 were approximately $93 million and $88 million, respectively, of which approximately $82 million and $79 million, respectively, were related to power purchases under the NUGs. Net power purchase activities with the counterparties to the NUGs for the nine months ended September 30, 2008 and 2007 were approximately $265 million and $248 million, respectively, of which approximately $233 million and $222 million, respectively, were related to power purchases under the NUGs. Pepco Holdings does not have loss exposure under the NUGs because cost recovery will be achieved from ACE’s customers through regulated rates.

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During the third quarter of 2008, Pepco transferred to Sempra Energy Trading LLP (Sempra) an agreement with Panda-Brandywine, L.P. (Panda) under which Pepco was obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (Panda PPA). Net purchase activities under the Panda PPA for the three months ended September 30, 2008 and 2007 were approximately $17 million and $24 million, respectively. Net purchase activities for the nine months ended September 30, 2008 and 2007 were approximately $59 million and $67 million, respectively. See Note (13) “Commitments and Contingencies — Regulatory and Other Matters — Proceeds from Settlement of Mirant Bankruptcy Claims.”

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $87.5 million and $90.3 million for the three months ended September 30, 2008 and 2007, respectively, and $235.6 million and $240.4 million for the nine months ended September 30, 2008 and 2007, respectively.

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. Substantially all of Pepco Holdings’ goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and was allocated to Pepco Holdings’ Power Delivery segment. Pepco Holdings tests its goodwill for impairment annually as of July 1, and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of a reporting unit below its carrying amount. In order to estimate the fair value of its Power Delivery segment, Pepco Holdings discounts the estimated future cash flows associated with the segment using a discounted cash flow model with a single interest rate that is commensurate with the risk involved with such an investment. The estimation of fair value is dependent on a number of factors, including but not limited to interest rates, future growth assumptions, operating and capital expenditure requirements and other factors, changes in which could materially impact the results of impairment testing. Pepco Holdings’ July 1, 2008 goodwill impairment testing indicated that its goodwill balance was not impaired. With the current volatile general market conditions and the disruption in the credit and capital markets, PHI will continue to monitor closely its goodwill balance.

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

Balance as of December 31, 2007	$	1,409.6
Less: Changes in estimates during the second quarter of 2008 related to pre-merger tax contingencies		(.6)
Balance as of September 30, 2008	$	1,409.0

Reclassifications and Adjustments

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

In the second quarter of 2008, Pepco recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to February 2005 where late

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payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $3.3 million. In the third quarter of 2008, DPL also recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to May 2006 where late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the three and nine months ended September 30, 2008 of $3.8 million and $2.8 million, respectively. In the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the Long-Term Incentive Plan (LTIP) which resulted in an understatement of stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in Other Operation and Maintenance expenses for the three and nine months ended September 30, 2008 of $8.8 million. These adjustments are not considered material either individually or in the aggregate.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 157, "Fair Value Measurements" (SFAS No. 157)

In September 2006, the FASB issued Statement of Financial Accounting Standards (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 to other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. Under 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 in the most advantageous market using the best available information. The provisions of SFAS No. 157 were effective for financial statements beginning 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 removed fair value measurement for the recognition and measurement of lease transactions from the scope of SFAS No. 157. The effective date of SFAS No. 157-1 was for financial statement periods beginning January 1, 2008 for PHI.

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), until financial statement reporting periods beginning January 1, 2009 for PHI.

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 required new disclosures regarding the level of pricing observability associated with financial instruments carried at fair value. This additional disclosure is provided in Note (12), “Fair Value Disclosures.” PHI is currently evaluating the impact of SFAS No. 157-2 on non-financial

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assets (including goodwill and liabilities); however, PHI does not anticipate that the application of SFAS No. 157 to its other non-financial assets and non-financial liabilities would materially affect its overall financial condition, results of operations or cash flows.

On September 30, 2008, the SEC and FASB issued guidance on fair value measurements, which was amplified on October 10, 2008 by the FASB in FSP Financial Accounting Standards (FAS) 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active.” This guidance clarifies the application of SFAS No. 157 to assets in an inactive market and illustrates how to determine the fair value of a financial asset in an inactive market. The guidance was effective beginning with the September 30, 2008 reporting period for PHI, and has not had a material impact on PHI’s results.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities–including an Amendment of FASB Statement No. 115” (SFAS No. 159)

On February 15, 2007, the FASB issued SFAS No. 159, which permits entities to elect to measure eligible financial instruments at fair value. SFAS No. 159 applies to other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. On January 1, 2008, Pepco Holdings did not elect the fair value option for its eligible financial assets and liabilities.

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

On April 30, 2007, the FASB issued FSP FIN 39-1 that amended certain portions of FASB Interpretation No. 39 (FIN 39). The FSP replaces the terms “conditional contracts” and “exchange contracts” in FIN 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 FIN 39 to allow for the offsetting of fair value amounts for the right to reclaim cash collateral or receivables, or the obligation to return cash collateral or payables, arising from the same master netting arrangement as the derivative instruments. FSP FIN 39-1 applied to financial statements beginning 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 (14), “Use Of Derivatives in Energy and Interest Rate Hedging Activities.” 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” (EITF 06-11)

On June 27, 2007, the FASB ratified Emerging Issues Task Force (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 non-vested equity shares, non-vested 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

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excess tax benefits available to absorb tax deficiencies on share-based payment awards. If the estimated amount of forfeitures increases or actual forfeitures reduce the amount of tax benefits previously recognized in APIC and if the APIC pool is depleted, then the reduction in tax benefit would be an adjustment to the income statement.

EITF 06-11 applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are granted during financial statement reporting periods beginning on January 1, 2008 for Pepco Holdings. Pepco Holdings adopted the provisions of EITF 06-11 on January 1, 2008, and 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” (SFAS No. 141 (R))

On December 4, 2007, the FASB issued 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 be used for all business combinations and for an acquirer to be identified for each business combination. However, SFAS No. 141 (R) expands the definition of a business and amends FASB Statement No. 109, “Accounting for Income Taxes” to require the acquirer to recognize changes in the amount of its deferred tax benefits that are realizable because of a business combination either in income from continuing operations or directly in contributed capital, depending on the circumstances.

SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009 for Pepco Holdings. Pepco Holdings is currently evaluating the potential impact SFAS No. 141(R) may have on its overall financial condition, results of operations, cash flows and footnote disclosure requirements.

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

On December 4, 2007, the FASB issued SFAS No. 160, which establishes new accounting and reporting standards for a non-controlling interest (also called a “minority interest”) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a minority interest in a subsidiary is an ownership interest in the consolidated entity that should be separately reported in the consolidated financial statements.

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

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SFAS No. 160 is effective prospectively for financial statement reporting periods beginning January 1, 2009 for Pepco Holdings, 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 and footnote disclosure requirements.

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

On March 19, 2008, the FASB issued SFAS No. 161, which changes the disclosure requirements for derivative instruments and hedging activities. Entities will be required to provide qualitative disclosures about derivatives objectives and strategies, fair value amounts of gains and losses on derivative instruments which before were optional, disclosure about credit-risk-related contingent features in derivative agreements, and information on the potential effect on an entity’s liquidity from using derivatives.

The Statement requires that the gross fair value of derivative instruments and gross gains and losses be quantitatively disclosed in a tabular format 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. The FASB provides an option for hedged items to be presented in the tabular or non-tabular format.

SFAS No. 161 is effective for financial statement reporting periods beginning January 1, 2009 for Pepco Holdings. 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.

SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162)

On May 9, 2008, the FASB issued SFAS No. 162, which identifies the sources of accounting principles and the hierarchy for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP in the United States. Moving the GAAP hierarchy into the accounting literature directs the responsibility for applying the hierarchy to the reporting entity, rather than just to the auditors.

SFAS No. 162 will be effective for Pepco Holdings as of November 15, 2008. The FASB believes that the application of SFAS No. 162 is not expected to result in a change in accounting; however, if it does, the accounting change must be reported as a change in accounting principle under SFAS No. 154, “Accounting Changes and Error Corrections.” Pepco Holdings is currently evaluating the impact SFAS No. 162 may have on its overall financial condition, results of operations, cash flows and footnote disclosure requirements.

FSP APB 14-1, “Accounting for Convertible Debt Instruments that may be Settled in Cash upon Conversion (Including Partial Cash Settlement)” (FSP APB 14-1)

On May 9, 2008, the FASB issued FSP Accounting Principles Board (APB) 14-1, which addresses the accounting for convertible debt securities that, upon conversion, may be settled by

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the issuer fully or partially in cash unless the embedded conversion option is required to be separately accounted for as a derivative under SFAS No. 133.

The liability and equity components of convertible debt instruments within the scope of FSP APB 14-1 shall be separately accounted for in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. Recognizing convertible debt instruments as two separate components, a debt component and an equity component, may result in a basis difference associated with the liability component that represents a temporary difference for purposes of applying SFAS No. 109, “Accounting for Income Taxes.” The initial recognition of deferred taxes for the tax effect of that temporary difference shall be recorded as an adjustment to additional paid-in capital.

FSP APB 14-1 is effective for financial statement reporting periods beginning January 1, 2009 for Pepco Holdings and shall be applied retrospectively to all periods presented. Pepco Holdings does not currently have any convertible debt instruments outstanding; however, these types of instruments may be considered for financing future endeavors.

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

On June 16, 2008, the FASB issued FSP EITF 03-6-1, which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (EPS) under the two-class method described in SFAS No. 128, “Earnings per Share.”

FSP EITF 03-6-1 is effective for financial reporting periods beginning January 1, 2009 for Pepco Holdings. All prior period EPS data presented shall be adjusted retrospectively (including interim financial statements, summaries of earnings, and selected financial data) to conform with the provisions of FSP EITF 03-6-1. Pepco Holdings is currently evaluating the impact FSP EITF 03-6-1 will have on its earnings per share calculations.

EITF Issue No. 07-05, “Determining Whether an Instrument (or Embedded Feature) is Indexed to an Entity’s Own Stock” (EITF 07-05)

On June 25, 2008, the FASB ratified EITF 07-05, which provides a two-step approach for determining whether an equity-linked financial instrument (or embedded feature) that has all of the characteristics of a derivative in paragraph 6-9 of SFAS No. 133 qualifies for the first part of the scope exception from derivative accounting in paragraph 11(a) of SFAS No. 133 for being “indexed to an entity’s own stock.” This issue also applies to any freestanding financial instrument that is settled in an entity’s own stock, regardless of whether an instrument has all the characteristics of a derivative. In addition, it includes derivative instruments that fall within the scope of EITF Issue 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company's Own Stock.” This issue supersedes EITF Issue No. 01-06, “The Meaning of ‘Indexed to a Company’s Own Stock’” and does not apply to share-based payment awards within the scope of SFAS No. 123(R), “Share-Based Payments.”

EITF 07-05 applies to financial statement periods beginning January 1, 2009 for Pepco Holdings to any outstanding instruments. The cumulative effect of the change in accounting principle shall be recognized as an adjustment to the opening balance of retained earnings for

PEPCO HOLDINGS

that fiscal year in which this issue is initially applied, presented separately. Pepco Holdings does not currently have any financial instruments that are indexed to its own stock outstanding; however, these types of instruments may be considered for financing future endeavors.

FSP FAS 133-1 and FIN 45-4, “Disclosure About Credit Derivatives and Certain Guarantees” (FSP FAS 133-1 and FIN 45-4)

On September 12, 2008, the FASB adopted FSP FAS 133-1 and FIN 45-4, which enhance disclosures by entities that provide credit protection through credit derivatives (including embedded credit derivatives) within the scope of SFAS No. 133, and guarantees within the scope of FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees Indebtedness of Others.” In addition, FSP FAS 133-1 clarifies the Board’s intent on the effective date for SFAS No. 161, “Disclosures about Derivatives Instruments and Hedging Activities.”

For credit derivatives, FSP FAS 133-1 requires disclosure on the nature and fair value of the credit derivative, the approximate term, the reasons for entering the derivative, the events requiring performance, and the current status of the payment/performance risk. It also requires disclosures of the maximum potential amount of future payments without any reduction for possible recoveries under collateral provisions, recourse provisions, or liquidation proceeds. For guarantees, FSP FAS 133-1 requires disclosure on the current status of the payment/performance risk and whether the current status is based on external credit ratings or current internal groupings used to manage risk. If internal groupings are used, then information is required about how the groupings are determined and used for managing risk.

The new disclosures are required starting with financial statement reporting periods ending December 31, 2008 for Pepco Holdings. Comparative disclosures are only required for periods ending after initial adoption. Pepco Holdings is currently evaluating the impact on its disclosures.

(5) LEASING ACTIVITIES

Investment in Finance Leases Held in Trust

As of September 30, 2008 and December 31, 2007, Pepco Holdings had cross-border energy lease investments of $1,321.2 million and $1,384.4 million, respectively, consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks located outside of the United States.

As further discussed in Note (2) and Note (13), PHI reassessed the sustainability of its tax position and revised its assumptions regarding the estimated timing of tax benefits generated from its cross-border energy lease investments during the second quarter of 2008. Based on this reassessment, PHI for the quarter ended June 30, 2008, recorded a reduction in its cross-border energy lease investments of $124.4 million. No further charges were considered necessary in the third quarter of 2008.

PEPCO HOLDINGS

The components of the cross-border energy lease investments at September 30, 2008 (reflecting the effects of recording this charge) and at December 31, 2007 are summarized below:

	September 30, 2008			December 31, 2007
	(Millions of dollars)

Scheduled lease payments, net of non-recourse debt	$	2,281.2		$	2,281.2
Less: Unearned and deferred income		(960.0	)		(896.8	)
Investment in finance leases held in trust		1,321.2			1,384.4
Less: Deferred income taxes		(664.8	)		(772.8	)
Net investment in finance leases held in trust	$	656.4		$	611.6

Income recognized from cross-border energy lease investments was comprised of the following for the three and nine months ended September 30, 2008 and 2007:

	Three Months Ended				Nine Months Ended
	September 30, 2008		September 30, 2007		September 30, 2008			September 30, 2007
	(Millions of dollars)
Pre-tax earnings from PHI’s cross-border energy lease investments (included in “Other Revenue”)	$	14.0	$	19.4	$	51.3		$	57.4
Non-cash charge to reduce equity value of PHI’s cross-border energy lease investments		-		-		(124.4	)		-
Pre-tax earnings (loss) from PHI’s cross-border energy lease investments after adjustment		14.0		19.4		(73.1	)		57.4
Income tax expense (benefit)		3.6		4.9		(25.4	)		11.0
Net income (loss) from PHI’s cross-border energy lease investments	$	10.4	$	14.5	$	(47.7	)	$	46.4

PEPCO HOLDINGS

(6) 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 September 30, 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 and nine months ended September 30, 2008 and 2007, is as follows.

	Three Months Ended September 30, 2008 (Millions of dollars)
				Competitive Energy Segments
	Power Delivery			Conectiv Energy			Pepco Energy Services		Other Non- Regulated		Corp. & Other (a)			PHI Cons.
Operating Revenue	$	1,667.6		$	782.8	(b)	$	715.7	$	14.2		$	(120.8)	$	3,059.5
Operating Expense (c)		1,495.4	(b)		693.9			713.0		1.6			(119.2)		2,784.7
Operating Income		172.2			88.9			2.7		12.6			(1.6)		274.8
Interest Income		2.8			.4			1.0		.9			(1.2)		3.9
Interest Expense		47.5			6.2			.8		4.9			21.9		81.3
Other Income (Expense)		2.4			-			.6		(1.8)			.3		1.5
Preferred Stock Dividends		.1			-			-		.7			(.7)		.1
Income Taxes		52.7			34.4			.5		1.4			(9.0)		80.0
Net Income (Loss)		77.1			48.7			3.0		4.7			(14.7)		118.8
Total Assets		9,874.9			2,046.9			708.3		1,465.1			1,477.4		15,572.6
Construction Expenditures	$	150.5		$	30.3		$	6.7	$	-		$	7.3	$	194.8

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 $(120.8) million for Operating Revenue, $(119.5) million for Operating Expense, $(14.3) million for Interest Income, $(13.6) 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 $113.3 million for the three months ended September 30, 2008.
(c)	Includes depreciation and amortization of $99.3 million, consisting of $84.0 million for Power Delivery, $9.4 million for Conectiv Energy, $3.6 million for Pepco Energy Services, $.5 million for Other Non-Regulated, and $1.8 million for Corp. & Other.

PEPCO HOLDINGS

	Three Months Ended September 30, 2007 (Millions of dollars)
		Competitive Energy Segments
	Power Delivery	Conectiv Energy	Pepco Energy Services	Other Non- Regulated	Corp. & Other (a)	PHI Cons.
Operating Revenue	$1,596.3	$ 633.2(b)	$654.4	$ 19.6	$ (133.2)	$ 2,770.3
Operating Expense (c)	1,376.6(b)(d)	566.4	638.1	1.2	(132.8)	2,449.5
Operating Income	219.7	66.8	16.3	18.4	(.4)	320.8
Interest Income	3.5	1.2	.7	2.9	(3.4)	4.9
Interest Expense	48.2	8.5	1.1	8.9	19.5	86.2
Other Income	4.9	.2	.6	2.7	-	8.4
Preferred Stock Dividends	.1	-	-	.6	(.6)	.1
Income Taxes	57.2(e)	23.2	6.7	3.3	(10.2)	80.2
Net Income (Loss)	122.6	36.5	9.8	11.2	(12.5)	167.6
Total Assets	9,763.6	1,782.4	650.8	1,669.6	1,191.3	15,057.7
Construction Expenditures	$ 122.3	$ 10.0	$ 3.7	$ -	$ 1.7	$ 137.7

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 $(133.4) million for Operating Revenue, $(132.2) million for Operating Expense, $(26.6) million for Interest Income, $(26.0) 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 $129.1 million for the three months ended September 30, 2007.
(c)	Includes depreciation and amortization of $87.6 million, consisting of $72.7 million for Power Delivery, $9.3 million for Conectiv Energy, $3.2 million for Pepco Energy Services, $.5 million for Other Non-Regulated and $1.9 million for Corp. & Other.
(d)	Includes $33.4 million ($20.0 million, after-tax) from settlement of Mirant bankruptcy claims.
(e)	Includes $19.5 million benefit related to the Maryland state income tax refund.

PEPCO HOLDINGS

	Nine Months Ended September 30, 2008 (Millions of dollars)
					Competitive Energy Segment
		Power Delivery			Conectiv Energy			Pepco Energy Services		Other Non- Regulated			Corp. & Other (a)		PHI Cons.
Operating Revenue	$	4,259.3		$	2,395.2	(b)	$	1,967.7	$	(72.7)	(d)	$	(330.9)	$	8,218.6
Operating Expense (c)		3,829.9	(b)		2,178.5			1,925.6		3.7			(331.3)		7,606.4
Operating Income		429.4			216.7			42.1		(76.4)			.4		612.2
Interest Income		11.6			1.9			2.2		2.9			(2.5)		16.1
Interest Expense		142.0			18.0			1.8		14.1			66.5		242.4
Other Income (Expense)		9.7			(.1)			1.8		(4.3)			1.0		8.1
Preferred Stock Dividends		.2			-			-		2.1			(2.1)		.2
Income Taxes		109.6			82.8			16.4		(25.2)	(d)		(22.8)		160.8
Net Income (Loss)		198.9			117.7			27.9		(68.8)	(d)		(42.7)		233.0
Total Assets		9,874.9			2,046.9			708.3		1,465.1			1,477.4		15,572.6
Construction Expenditures	$	432.2		$	89.7		$	23.5	$	-		$	15.2	$	560.6

Notes:
(a)	Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date. Additionally, the Total Assets line item in this column includes Pepco Holdings’ goodwill balance. Included in Corp. & Other are intercompany amounts of $(330.9) million for Operating Revenue, $(326.7) million for Operating Expense, $(42.5) million for Interest Income, $(40.4) million for Interest Expense, and $(2.1) million for Preferred Stock Dividends.
(b)	Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $297.7 million for the nine months ended September 30, 2008.
(c)	Includes depreciation and amortization of $282.9 million, consisting of $238.5 million for Power Delivery, $27.8 million for Conectiv Energy, $9.5 million for Pepco Energy Services, $1.4 million for Other Non-Regulated, and $5.7 million for Corp. & Other.
(d)	Included in operating revenue is a pre-tax charge of $124.4 million ($86.0 million after-tax) related to the adjustment to the equity value of cross-border energy lease investments, and included in income taxes is a $6.9 million after-tax charge for the additional interest accrued on the related tax obligations. (See Note (2), Note (5), Note (9) and Note (13) herein for additional information.)

PEPCO HOLDINGS

	Nine Months Ended September 30, 2007 (Millions of dollars)
		Competitive Energy Segments
	Power Delivery	Conectiv Energy	Pepco Energy Services	Other Non- Regulated	Corp. & Other (a)	PHI Cons.
Operating Revenue	$4,033.7	$1,607.5(b)	$1,686.9	$ 58.0	$ (352.7)	$ 7,033.4
Operating Expense (c)	3,606.7(b)(d)	1,491.4	1,652.8	3.3	(350.2)	6,404.0
Operating Income	427.0	116.1	34.1	54.7	(2.5)	629.4
Interest Income	6.5	4.1	2.2	8.3	(9.4)	11.7
Interest Expense	138.7	24.9	2.8	26.9	61.3	254.6
Other Income	14.7	.3	4.4	10.2	.9	30.5
Preferred Stock Dividends	.3	-	-	1.8	(1.8)	.3
Income Taxes	107.0(e)	38.3	14.8	7.1	(26.9)	140.3
Net Income (Loss)	202.2	57.3	23.1	37.4	(43.6)	276.4
Total Assets	9,763.6	1,782.4	650.8	1,669.6	1,191.3	15,057.7
Construction Expenditures	$ 377.7	$ 30.0	$ 10.7	$ -	$ 4.3	$ 422.7

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 $(352.9) million for Operating Revenue, $(349.4) million for Operating Expense, $(70.8) million for Interest Income, $(69.0) million for Interest Expense, and $(1.8) million for Preferred Stock Dividends.
(b)	Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $335.3 million for the nine months ended September 30, 2007.
(c)	Includes depreciation and amortization of $273.4 million, consisting of $228.4 million for Power Delivery, $27.9 million for Conectiv Energy, $9.3 million for Pepco Energy Services, $1.4 million for Other Non-Regulated and $6.4 million for Corp. & Other.
(d)	Includes $33.4 million ($20.0 million, after-tax) from settlement of Mirant bankruptcy claims.
(e)	Includes $19.5 million benefit related to the Maryland state income tax refund.

PEPCO HOLDINGS

(7) PENSIONS AND OTHER POSTRETIREMENT BENEFITS

The following Pepco Holdings information is for the three months ended September 30, 2008 and 2007.

		Pension Benefits				Other Postretirement Benefits
		2008		2007		2008		2007
	(Millions of dollars)
Service cost	$	9.1	$	12.7	$	1.8	$	1.8
Interest cost		26.9		25.4		10.0		9.2
Expected return on plan assets		(32.5)		(32.6)		(3.9)		(3.3)
Prior service cost/(credit) component		.1		.2		(1.0)		(1.1)
Loss component		2.4		2.4		3.2		2.8
Curtailment/settlement loss		-		3.0		-		-
Net periodic benefit cost	$	6.0	$	11.1	$	10.1	$	9.4

The following Pepco Holdings information is for the nine months ended September 30, 2008 and 2007.

		Pension Benefits				Other Postretirement Benefits
		2008		2007		2008		2007
	(Millions of dollars)
Service cost	$	27.2	$	30.8	$	5.3	$	5.4
Interest cost		80.8		76.3		30.1		27.5
Expected return on plan assets		(97.5)		(97.7)		(11.8)		(10.0)
Prior service cost/(credit) component		.3		.6		(3.1)		(3.1)
Loss component		7.2		6.5		9.8		8.9
Curtailment/settlement loss (gain)		-		3.6		-		(.4)
Net periodic benefit cost	$	18.0	$	20.1	$	30.3	$	28.3

Pension

The pension net periodic benefit cost for the three months ended September 30, 2008, of $6.0 million includes $2.8 million for Pepco, $.6 million for ACE, and $(1.4) million for DPL. The pension net periodic benefit cost for the nine months ended September 30, 2008, of $18.0 million includes $8.5 million for Pepco, $1.9 million for ACE, and $(4.1) million for DPL. The pension net periodic benefit cost for the three months ended September 30, 2007, of $11.1 million includes $2.3 million for Pepco, $.7 million for ACE, and $(1.4) million for DPL. The pension net periodic benefit cost for the nine months ended September 30, 2007, of $20.1 million includes $6.8 million for Pepco, $2.0 million for ACE, and $(4.2) million for DPL. The remaining pension net periodic benefit cost is for other PHI subsidiaries.

PEPCO HOLDINGS

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. As of September 30, 2008 and 2007, no contributions were made for the respective years. 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 and the discount rate at year-end.

Other Postretirement Benefits

The other postretirement net periodic benefit cost for the three months ended September 30, 2008, of $10.1 million includes $3.2 million for Pepco, $2.3 million for ACE and $2.2 million for DPL. The other postretirement net periodic benefit cost for the nine months ended September 30, 2008, of $30.3 million includes $9.6 million for Pepco, $6.9 million for ACE and $6.6 million for DPL. The other postretirement net periodic benefit cost for the three months ended September 30, 2007, of $9.4 million includes $3.3 million for Pepco, $2.2 million for ACE and $2.0 million for DPL. The other postretirement net periodic benefit cost for the nine months ended September 30, 2007, of $28.3 million includes $10.0 million for Pepco, $6.7 million for ACE and $6.0 million for DPL. The remaining other postretirement net periodic benefit cost is for other PHI subsidiaries.

(8) DEBT

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

As a result of severe liquidity constraints in the credit, commercial paper and capital markets during September 2008, PHI, Pepco, and ACE borrowed under the $1.5 billion credit facility. Typically, the companies issue commercial paper if required to meet their short-term working capital requirements. Given the lack of liquidity in the commercial paper markets, the companies borrowed under the credit facility to maintain sufficient cash on hand to meet daily short-term operating needs. At September 30, 2008, PHI borrowed $200 million, Pepco borrowed $100 million, and ACE borrowed $135 million. These LIBOR-based loans matured during October 2008 and were rolled to November 2008. In October 2008, PHI borrowed an additional $50 million, Pepco borrowed an additional $100 million and DPL borrowed $150 million.

In July 2008, DPL amended a $150 million loan agreement to convert it from a two-year loan into a 364 day facility that matures in July 2009.

PEPCO HOLDINGS

In July 2008, ACE Funding made principal payments of $2.6 million on Series 2002-1 Bonds, Class A-1, $2.3 million on Series 2002-1 Bonds, Class A-2, and $1.9 million on Series 2003-1 Bonds, Class A-1.

In July 2008, ACE repurchased $3.8 million of Pollution Control Revenue Refunding Bonds 1997 Series A issued by Salem County for the benefit of ACE that were tendered by the holders for purchase at par. The purchase of these Variable Rate Demand Bonds was financed by The Bank of New York under a Standby Bond Purchase Agreement relating to the series.

In August 2008, DPL repurchased, on the mandatory put date, $18.2 million of Exempt Facilities Revenue Bonds, 2003B Series due 2023, issued by the Delaware Economic Development Authority for the benefit of DPL. The bonds are considered to be extinguished for accounting purposes, although they remain outstanding, registered in DPL’s name, pending a decision by DPL to resell or retire the bonds.

In September 2008, Pepco repaid at maturity, a $25 million short-term loan.

(9) INCOME TAXES

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

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2008		2007		2008		2007

Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	.9		.7		1.3		1.5
Asset removal costs	(.3)		(.2)		(.7)		(.4)
State income taxes, net of federal effect	5.9		4.3		7.5		3.9
Tax credits	(.5)		(.6)		(.8)		(.9)
Adjustments to prior years’ taxes	(.7)		-		(.3)		-
PHI’s cross-border energy lease investments	(.7)		(.8)		.2		(1.4)
Change in estimates and interest related to uncertain and effectively settled tax positions	1.2		.8		(.9)		(.1)
Software amortization	.3		.4		.4		.6
Maryland state tax refund and interest	(.2)		(7.9)		(.7)		(4.7)
Deferred tax adjustment	-		1.3		-		.8
Other, net	(.7)		(.6)		(.2)		(.7)

Consolidated Effective Income Tax Rate	40.2	%	32.4	%	40.8	%	33.6	%

PHI’s effective tax rates for the three months ended September 30, 2008 and 2007 were 40.2% and 32.4%, respectively. The increase in the effective tax rate was primarily due to an increase in changes in estimates and interest related to uncertain and effectively settled tax positions, and the receipt of Pepco’s Maryland state tax refund recorded in 2007. This increase is partially offset by a deferred tax adjustment recorded in the third quarter of 2007.

PHI’s effective tax rates for the nine months ended September 30, 2008 and 2007 were 40.8% and 33.6%, respectively. The increase in the effective tax rate was primarily due to the receipt of Pepco’s Maryland state tax refund recorded in 2007, and was partially offset by an increase in tax benefits related to changes in estimates and interest related to uncertain and effectively settled tax positions.

PEPCO HOLDINGS

During the second quarter of 2008, PHI reached a tentative settlement with the IRS concerning the treatment by Pepco, DPL and ACE of mixed service costs for income tax purposes during the period 2001 to 2004. See “Commitments and Contingencies — Regulatory and Other Matters — IRS Mixed Service Cost Issue” in Note (13). On the basis of the tentative settlement, PHI updated its estimated liability related to mixed service costs and as a result, recorded a net reduction in its liability for unrecognized tax benefits of $18.7 million and recognized after-tax interest income of $7.2 million in the second quarter of 2008.

As further discussed in the “Commitments and Contingencies — Regulatory and Other Matters — IRS Examination of Like-Kind Exchange Transaction” in Note (13), in October 2008, the Company and the IRS came to an agreement on this issue whereby the Company will pay approximately $2.0 million of tax and interest. As a result of this settlement, PHI expects to reverse the excess accrued interest in the fourth quarter.

(10) STOCK-BASED COMPENSATION

No stock options were granted in the nine months ended September 30, 2008.

There were no stock options exercised under all share-based payment arrangements for the three months ended September 30, 2008. Cash received from options exercised under all share-based payment arrangements for the nine months ended September 30, 2008, was $2.9 million and the tax benefit realized for the tax deductions resulting from these options exercised totaled $.2 million.

PEPCO HOLDINGS

(11) 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 September 30,
			2008		2007
	(In millions, except per share data)
Income (Numerator):
Earnings Applicable to Common Stock		$	118.8	$	167.6

Shares (Denominator) (a):
Weighted average shares outstanding for basic computation:
Average shares outstanding			201.8		193.5
Adjustment to shares outstanding			(.3)		(.2)
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock			201.5		193.3
Net effect of potentially dilutive shares			.4		.5
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock			201.9		193.8

Basic earnings per share of common stock		$	.59	$	.87
Diluted earnings per share of common stock		$	.59	$	.87

(a)

The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS as they are considered to be anti-dilutive were approximately 171,000 and 5,000 for the three months ended September 30, 2008 and 2007, respectively.

PEPCO HOLDINGS

	For the Nine Months Ended September 30,
			2008		2007
	(In millions, except per share data)
Income (Numerator):
Net Income		$	233.0	$	276.4
Add: Loss on redemption of subsidiary’s preferred stock			-		(.6)
Earnings Applicable to Common Stock		$	233.0	$	275.8

Shares (Denominator) (a):
Weighted average shares outstanding for basic computation:
Average shares outstanding			201.4		193.1
Adjustment to shares outstanding			(.3)		(.3)
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock			201.1		192.8
Net effect of potentially dilutive shares			.4		.5
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock			201.5		193.3

Basic earnings per share of common stock		$	1.16	$	1.43
Diluted earnings per share of common stock		$	1.16	$	1.43

(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 for the nine months ended September 30, 2008 and 2007, respectively.

(12) 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 expanded disclosures about fair value measurements.

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

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

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

Level 3 – Pricing inputs include significant inputs that are generally less observable than those from objective sources. Level 3 includes those financial 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.

The following table sets forth by level within the fair value hierarchy PHI's financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 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.

	Fair Value Measurements at Reporting Date Using
	(Millions of dollars)
Description	September 30, 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	$	164.1	$	73.8	$	86.9	$	3.4
Cash equivalents		341.2		341.2		-		-
Executive deferred compensation plan assets		78.2		14.7		46.7		16.8
	$	583.5	$	429.7	$	133.6	$	20.2

LIABILITIES
Derivative instruments	$	277.3	$	87.3	$	180.4	$	9.6
Executive deferred compensation plan liabilities		35.3		-		35.3		-
	$	312.6	$	87.3	$	215.7	$	9.6

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

	Net Derivative Instruments		Deferred Compensation Plan Assets
Beginning balance as of January 1, 2008	$	.6	$	17.1
Total gains or (losses) (realized/unrealized)
Included in earnings		1.4		2.8
Included in other comprehensive income		-		-
Purchases and issuances		-		(3.1)
Settlements		2.5		-
Transfers in and/or out of Level 3		(10.7)		-
Ending balance as of September 30, 2008	$	(6.2)	$	16.8


Gains (realized and unrealized) included in earnings 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 for the period above	$	1.4	$	2.8

Change in unrealized gains relating to assets still held at reporting date	$	2.3	$	2.8

(13) COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Proceeds from Settlement of Mirant Bankruptcy Claims

In 2000, Pepco sold substantially all of its electricity generating assets to Mirant Corporation and certain of its subsidiaries (collectively, Mirant). 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 was obligated to purchase annually through 2021 from Panda under the Panda PPA at the purchase price Pepco was obligated to pay to Panda. In 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 was 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. Upon receipt, these funds were 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 was 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.

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On September 5, 2008, Pepco transferred the Panda PPA to Sempra Energy Trading LLC (Sempra) in a transaction in which Pepco made a payment to Sempra from the restricted cash account and any further Pepco rights, obligations and liabilities under the Panda PPA were terminated. The payment to Sempra reduced the balance of restricted cash equivalents related to this matter to approximately $100.4 million as of September 30, 2008.

Pepco intends to file revised rates with the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC) in the fourth quarter of 2008 for the purpose of distributing the remaining funds in the restricted cash account. The portion of the balance of the funds in the restricted cash account that Pepco ultimately retains will depend on the customer sharing arrangements approved by the DCPSC and the MPSC.

Rate Proceedings

In electric service distribution base rate cases filed by Pepco in the District of Columbia and Maryland, and by DPL in Maryland, and in a natural gas distribution case filed by DPL in Delaware, 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 increases rates if actual distribution revenues fall below the level approved by the applicable commission and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, the utility collects its authorized revenues for distribution deliveries. As a consequence, a BSA “decouples” revenue from unit sales 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.

Delaware

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customer charge (i.e., not tied to the customer’s volumetric consumption) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, DPL believes that the MFRVD can serve as an appropriate revenue decoupling mechanism. The specific rate design of a proposed MFRVD will be established in the context of DPL’s next base rate case (presumably electric); however, the DPSC retained the flexibility to address these rate design changes outside of a base rate case if the situation is warranted. This would permit the DPSC to apply a MFVRD to DPL’s natural gas rates without the necessity of a full base rate case.

In September 2007, DPL submitted its 2007 Gas Cost Rate (GCR) filing to the DPSC, which permits DPL to recover gas procurement costs through customer rates. The filing requested a 5.7% decrease in the level of the GCR. Later that same month, the DPSC issued an initial order approving the requested decrease, which became effective November 1, 2007, subject to refund and pending final DPSC approval after evidentiary hearings. Those rates were made permanent by the DPSC on September 16, 2008 and are effective through October 31, 2008.

On August 29, 2008, DPL submitted its 2008 GCR filing to the DPSC, requesting a 14.8% increase in the level of GCR. On September 16, 2008, the DPSC issued an initial order approving the requested increase, which became effective on November 1, 2008, subject to refund and pending final DPSC approval after evidentiary hearings.

District of Columbia

In December 2006, Pepco submitted an application to the DCPSC to increase electric distribution base rates, including a proposed BSA. In January 2008, the DCPSC approved, effective February 20, 2008, a revenue requirement increase of approximately $28.3 million, based on an authorized return on rate base of 7.96%, including a 10% return on equity (ROE). The District of Columbia Office of People’s Counsel (OPC) filed with the DCPSC a motion for reconsideration of the January 2008 order granting Pepco’s rate increase and, on June 13, 2008, the DCPSC issued an order denying the OPC’s motion. On August 12, 2008, the OPC filed with the District of Columbia Court of Appeals a petition for review of the DCPSC’s June 13, 2008 order denying reconsideration of its January 2008 order.

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. On August 21, 2008, the DCPSC issued an order concluding that it has the necessary statutory authority to implement the BSA proposal and further evidentiary proceedings are warranted to determine whether the BSA is just and reasonable.

Maryland

In July 2007, the MPSC issued orders in the electric service distribution rate cases filed by DPL and Pepco, each of which included approval of a BSA. The DPL order approved an annual increase in distribution rates of approximately $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,

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2007, and remained in effect for an initial period until July 19, 2008, pending a Phase II proceeding in which the MPSC considered the results of audits of each company’s cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates was required. On July 18, 2008, the MPSC issued one order covering the Phase II proceedings for both DPL and Pepco, denying any further adjustment to the rates for each company, thus making permanent the rate increases approved in the July 2007 orders. The MPSC also issued an order on August 4, 2008, further explaining its July 18 order.

On August 18, 2008, DPL and Pepco each filed a general notice of appeal of both the July 18 and August 4 orders (under Maryland rules, a petitioner is not required to specify the basis of the appeal in the notice of appeal). The DPL appeal was filed in the Circuit Court for Cecil County, Maryland, and the Pepco appeal was filed in the Circuit Court for Montgomery County, Maryland. The Pepco filing included a motion to transfer the proceeding to Cecil County. The MPSC filed a motion to transfer the proceedings from the Circuit Courts of Montgomery County and Cecil County to the Circuit Court for Baltimore City. A motions hearing has been scheduled for December 1, 2008 in Cecil County. No action has been taken in Montgomery County. DPL’s memorandum on appeal, which will specify the basis of DPL’s appeal, is due in the Cecil County Circuit on November 17, 2008.

Federal Energy Regulatory Commission

On August 18, 2008, PHI, Pepco, DPL and ACE submitted an application with the Federal Energy Regulatory Commission (FERC) for incentive rate treatments in connection with PHI’s 230-mile, 500-kilovolt Mid-Atlantic Power Pathway Project (the MAPP Project). The application requested that FERC include all of the respective utilities’ Construction Work in Progress in rate base, an ROE adder of 150 basis points and the recovery of prudently incurred costs in the event the project is abandoned or terminated for reasons beyond the control of the applicants. On October 31, 2008, FERC granted unanimous approval of the requested rate incentives.

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 implementing regulations. As of September 30, 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. Other issues in the divestiture proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.

Pepco believes that a sharing of EDIT and ADITC would violate the IRS normalization rules. Under these rules, Pepco could not transfer the EDIT and the ADITC benefit to

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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 September 30, 2008), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3.5 million as of September 30, 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.

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 September 30, 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

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approximately 50/50 basis, the Maryland allocated portion of the generation-related EDIT ($9.1 million as of September 30, 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 September 30, 2008), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($6.3 million as of September 30, 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, depending on the ultimate outcome of this proceeding, Pepco could be required to share with its customers approximately 50 percent of the EDIT and ADITC balances described above in addition to the additional gain-sharing payments relating to the disallowed severance payments. Such additional payments would be charged to expense in the quarter and year in which a final decision is rendered and could have a material adverse effect on results of operations for those periods. However, neither PHI nor Pepco believes that additional gain-sharing payments, if any, or the ADITC-related payments to the IRS, if required, would have a material adverse impact on its financial position or cash flows.

ACE Sale of B.L. England Generating Facility

In February 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy Investments, LLC. In July 2007, ACE received a claim for indemnification from RC Cape May under the purchase agreement in the amount of $25 million. RC Cape May contends that one of the assets it purchased, a contract for terminal services (TSA) between ACE and Citgo Asphalt Refining Co. (Citgo), has been declared by Citgo to have been terminated due to a failure by ACE to renew the contract in a timely manner. 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. The claim for indemnification seeks payment from ACE in the event the TSA is held not to be enforceable against Citgo. While ACE believes that it has defenses to the indemnification claim, 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 arbitration hearings began in the last week of October 2008.

DPL Sale of Virginia Operations

In January 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

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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 that became known within six months after the January 2, 2008 closing date. The allowance period for A&N and/or ODEC to notify DPL has passed and no notification was made with respect to the discovery of additional pre-closing liabilities. A&N delayed final payment of approximately $3.5 million, which was due on June 2, 2008, due to a dispute in the final true-up amounts. On October 21, 2008, DPL and A&N entered into a Settlement Agreement pursuant to which A&N has paid $3.5 million to DPL, and an additional $.5 million has been distributed to DPL pursuant to an escrow agreement.

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 September 30, 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 the remaining plaintiffs are greatly exaggerated. The amount of total liability, if any, and any related insurance recovery cannot be determined at this time; however, based on information and relevant circumstances known at this time, neither PHI nor Pepco believes these suits will have a material adverse effect on its financial position, results of operations or cash flows. However, if an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco’s and PHI’s financial position, results of operations or cash flows.

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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.

In September 2007, the Delaware District Court issued an order granting summary judgment in favor of the PHI Parties. In October 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 in March 2008. On September 22, 2008, the U.S. Court of Appeals for the Third Circuit heard oral arguments on the appeal.

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 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

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regulations are not recoverable from customers of the operating utilities, environmental clean-up costs incurred by Pepco, DPL and ACE would be included by each company in its respective cost of service for ratemaking purposes.

Delilah Road Landfill Site. In 1991, the New Jersey Department of Environmental Protection (NJDEP) identified ACE as a potentially responsible party (PRP) at the Delilah Road Landfill site in Egg Harbor Township, New Jersey. In 1993, ACE, along with other PRPs, signed an administrative consent order with NJDEP to remediate the site. The soil cap remedy for the site has been implemented and in August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site. Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years. In September 2007, NJDEP approved the PRP group’s petition to conduct semi-annual, rather than quarterly, ground water monitoring for two years and deferred until the end of the two-year period a decision on the PRP group’s request for annual groundwater monitoring thereafter. In August 2007, the PRP group agreed to reimburse the costs of the U.S. Environmental Protection Agency (EPA) in the amount of $81,400 in full satisfaction of EPA’s claims for all past and future response costs relating to the site (of which ACE’s share is one-third). Effective April 11, 2008, EPA and the PRP group entered into a settlement agreement which will allow EPA to reopen the settlement in the event of new information or unknown conditions at the site. Based on information currently available, ACE anticipates that its share of additional cost associated with this site for post-remedy operation and maintenance will be approximately $555,000 to $600,000. 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. In June 2007, ACE received a letter from the New York Department of Environmental Conservation (NYDEC) identifying ACE as a PRP at the Frontier Chemical Waste Processing Company site in Niagara Falls, N.Y. based on hazardous waste manifests indicating that ACE sent in excess of 7,500 gallons of manifested hazardous waste to the site. ACE has entered into an agreement with the other parties identified as PRPs to form 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.

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 early 2008, EPA, the PRP group and the State of North Carolina entered into a settlement agreement under which (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 covenanted not to sue or bring administrative action against DPL and Pepco for response costs at the site, (iii) other PRP group members released all rights for cost recovery or contribution claims they may have against DPL and Pepco, and (iv) DPL and Pepco released all rights for cost recovery or contribution claims that they may have against other parties settling with EPA and the State of North Carolina. On September 24, 2008, the U.S. District Court for the Eastern District of North Carolina entered a consent decree which resolves DPL’s and Pepco’s liability at the site.

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Deepwater Generating Station Revocation Order. In December 2005, NJDEP issued a Title V operating permit (the 2005 Permit) to Deepwater Generating Station (Deepwater) owned by Conectiv Energy. Conectiv Energy appealed several provisions of the 2005 Permit and a revised Title V operating permit issued in 2008 (the 2008 Permit) and administrative litigation is ongoing. On February 5, 2008, NJDEP issued an order (the First Order) revoking the Deepwater operating permit. The order is based on the NJDEP’s contention that Deepwater Unit 6/8 operated in violation of its emission limit for hydrogen chloride (HCl) and total suspended particles (TSP) during a December 2007 stack test. The order also assessed a penalty for the incident in the amount of $30,000. Conectiv Energy has filed an appeal of both the revocation order and the penalty with the Office of Administrative Law. The effectiveness of the revocation order has been stayed by the NJDEP through January 9, 2009.

On July 17, 2008, NJDEP issued an order (the Second Order) revoking the Deepwater operating permit. The order is based on the NJDEP’s contention that Deepwater Unit 6/8 operated in violation of its emission limit for particulate matter less than 10 microns (PM-10) during the December 2007 stack test. The order also assessed a penalty for the incident in the amount of $10,000. Conectiv Energy has filed an appeal of both the revocation order and the penalty with the Office of Administrative Law. The effectiveness of the revocation order has been stayed by the NJDEP through January 9, 2009.

Subsequent stack tests have confirmed that Unit 6/8 complies with its emission limits for TSP and PM-10. On September 8, 2008, NJDEP issued an order (the Third Order) requiring Conectiv Energy to operate Deepwater Unit 6/8 in compliance with its HCl limit or in the alternative revoking Unit 6/8’s operating permit effective October 21, 2008. The Third Order is based on the NJDEP’s contention that Unit 6/8 violated the HCl limit on 106 days between December 5, 2007 and April 24, 2008 stack tests. The order also assessed a penalty in the amount of $5.3 million. Conectiv Energy has appealed both the revocation order and the penalty. The effectiveness of the revocation order has been stayed by the NJDEP through January 9, 2009.

Conectiv Energy is operating Deepwater 6/8 while firing coal at a reduced load, or at full load with lime injection, to comply with the challenged HCl permit limit at all potential coal chloride contents. Operation with lime injection was authorized by the Environmental Improvement Test Pilot permit issued by NJDEP on September 18, 2008, which facilitates assessment of the feasibility and practicality of hydrated lime injection technology in controlling HCl emissions from Unit 6/8 at full load without significantly impacting boiler operations.

Conectiv Energy believes that it has strong legal arguments that NJDEP cannot revoke the permit prior to an administrative hearing and believes that the probability of a complete shut-down of the unit is low because the unit appears to be in compliance with the HCl limit. With regard to the $5.3 million penalty assessment, Conectiv Energy’s appeal asserts that (1) the HCl limit in the 2008 Permit was illegally set at an unachievable level given the inherent variability of chloride content in coal; (2) during the December 2007 stack test that NJDEP relied upon to assess the fine, Deepwater Unit 6/8 experienced a malfunction and Conectiv Energy claimed the statutory affirmative defense for any excess emissions; (3) NJDEP has not provided any specific justification for the penalty amount or its appropriateness, given significantly lower fines for prior HCl exceedances by Unit 6/8, other than the fact that Unit 6/8 continued to operate after the December 2007 stack test; and (4) NJDEP improperly assessed

PEPCO HOLDINGS

the penalty at a time when a stay of a prior revocation order was in effect and the parties were working on setting an achievable HCl limit and while Conectiv Energy was implementing the lime injection pilot project.

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 U.S. Office of Appeals of the IRS (Appeals Office).

As of September 30, 2008, PHI had accrued approximately $5.8 million of after-tax interest liability related to this matter. In October 2008, Conectiv and the IRS agreed on a settlement under which Conectiv will pay approximately $2.0 million of tax and interest. As a result of this settlement, PHI expects to reverse the excess accrued interest in the fourth quarter.

PHI’s Cross-Border Energy Lease Investments

Between 1994 and 2002, Potomac Capital Investment Corporation (PCI), a subsidiary of PHI, entered into eight cross-border energy lease investments involving public utility assets (primarily consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks) located outside of the United States. Each of these investments is structured as a sale and leaseback transaction commonly referred to as a sale-in/lease-out or SILO transaction. Prior to the reassessment discussed below, PHI had historically derived approximately $74 million per year in tax benefits from these eight cross-border energy lease investments (reflecting 100% of the tax benefits) to the extent that rental income under the leases is exceeded by the depreciation deductions on the purchase price of the assets and interest deductions on the non-recourse debt financing (obtained by PCI to fund a substantial portion of the purchase price of the assets). PHI’s annual tax benefits are now approximately $56 million after giving effect to the reassessment. As of September 30, 2008, PHI’s equity investment in its cross-border energy leases was approximately $1.3 billion which included the impact of the reassessment discussed below. During the period from January 1, 2001 to September 30, 2008, PHI has derived approximately $447 million in federal income tax benefits from the depreciation and interest deductions in excess of rental income with respect to these cross-border energy lease investments, which includes the effect of the reassessment discussed below.

In 2005, the Treasury Department and IRS issued Notice 2005-13 identifying sale-leaseback transactions with certain attributes entered into with tax-indifferent parties as tax

PEPCO HOLDINGS

avoidance transactions, and the IRS announced its intention to disallow the associated tax benefits claimed by the investors in these transactions. PHI’s cross-border energy lease investments, each of which is with a tax-indifferent party, have been under examination by the IRS as part of the normal PHI federal income tax audits. In the final RAR issued in June 2006 in connection with the audit of PHI’s 2001 and 2002 income tax returns, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to six of its cross-border energy lease investments. In addition, the IRS has sought to recharacterize the leases as loan transactions as to which PHI would be subject to original issue discount income. PHI is protesting the IRS adjustments and the unresolved audit issues have been forwarded to the Appeals Office. PHI is in the early stages of discussions with the Appeals Office. If these discussions are unsuccessful, PHI currently intends to pursue litigation proceedings against the IRS to defend its tax position. While the audits of PHI’s federal income tax returns for subsequent tax years are ongoing or have not yet commenced, PHI anticipates that the IRS will take the same position with respect to each of the subsequent years on all eight of its cross-border energy lease investments.

In the last several years, IRS challenges to certain cross-border lease transactions have been the subject of litigation. This litigation has resulted in several decisions in favor of the IRS, including two decisions in the second quarter of 2008. In one of the cases decided in the second quarter relating to a lease-in/lease-out transaction, a United States Court of Appeals upheld a lower court decision in favor of the IRS to disallow the tax benefits taken by the taxpayer. In the second case, a United States District Court rendered an opinion concerning a SILO transaction in which it upheld the IRS’s disallowance of tax benefits taken by the taxpayer. Under FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), the financial statement recognition of an uncertain tax position is permitted only if it is more likely than not that the position will be sustained. Further, under FASB Staff Position No. 13-2, “Accounting for a Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged-lease Transaction” (FSP 13-2), a company is required to assess on a periodic basis the likely outcome of tax positions relating to its cross-border energy lease investments and, if there is a change or a projected change in the timing of the tax benefits generated by the transactions, the company is required to recalculate the value of its equity investment.

While PHI believes that its tax position with regard to its cross-border energy lease investments is appropriate based on applicable statutes, regulations and case law, after evaluating the recent court rulings described above, PHI at June 30, 2008 reassessed the sustainability of its tax position and has revised its assumptions regarding the estimated timing of the tax benefits from its cross-border energy lease investments. Based on this reassessment, PHI for the quarter ended June 30, 2008, recorded an after-tax charge to net income of $92.9 million, consisting of the following components:

·	A non-cash pre-tax charge of $124.4 million ($86.0 million after tax) under FSP 13-2 to reduce the equity value of these cross-border energy lease investments. This pre-tax charge has been recorded in the Consolidated Statement of Earnings as a reduction in other operating revenue.

·	A non-cash charge of $6.9 million after-tax to reflect the anticipated additional interest expense under FIN 48 on the estimated federal and state income tax that would be

PEPCO HOLDINGS

payable for the period January 1, 2001 through June 30, 2008, based on the revised assumptions regarding the estimated timing of the tax benefits. This after-tax charge has been recorded in the Consolidated Statement of Earnings as an increase in income tax expense.

The charge pursuant to FSP 13-2 reflects changes to the book equity value of the cross-border energy lease investments and the pattern of recognizing the related cross-border energy lease income. This amount will be recognized as income over the remaining term of the affected leases, which expire between 2017 and 2047. The tax benefits associated with the lease transactions represent timing differences that do not change the aggregate amount of the lease net income over the life of the transactions. Consistent with the revised assumptions regarding the estimated timing of the tax benefits, PHI reduced the tax benefits recorded on its 2007 tax return filed in September 2008 and accordingly paid additional federal and state income taxes. Other than these payments made with the 2007 tax return and estimated tax payments made in 2008 associated with the reduced tax benefits, PHI has made no additional cash payments of federal or state income taxes or interest thereon as a result of the reassessment discussed above. Whether PHI makes a payment, and the amount and the timing thereof, will depend on a number of factors, including PHI’s litigation strategy, whether a settlement with the IRS can be reached or whether the company decides to deposit funds with the IRS to avoid higher interest costs, until the issue is resolved. PHI is continuing to defend vigorously its tax position with the IRS.

In connection with the recording of the above adjustment, PHI calculated as of June 30, 2008, the additional non-cash charge to earnings that would have been recorded resulting from the disallowance of the entire amount of the tax benefits from the depreciation and interest deductions in excess of rental income and the recharacterization of the transactions as loans over the period from January 1, 2001 through the end of the lease term. PHI would have incurred an additional non-cash charge to earnings at June 30, 2008 of approximately $346.3 million consisting of:

·	A non-cash charge of $323.5 million ($293.0 million after tax) under FSP 13-2 to further reduce the equity value of these cross-border energy lease investments.

·	A non-cash charge of $53.3 million after-tax to reflect the anticipated additional interest expense under FIN 48 on the estimated federal and state income tax for the period from January 1, 2001 through June 30, 2008.

No changes in the assumptions have occurred which would materially impact these estimates disclosed at June 30, 2008.

In the event of the total disallowance of the tax benefits and the imputing of original issue discount income due to the recharacterization of the lease as loans, PHI would have been obligated to pay, as of September 30, 2008, approximately $518.4 million in additional federal and state taxes and $76.5 million of interest. In addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due. PHI anticipates that any additional taxes that it would be required to pay as a result of the disallowance of prior deductions or a recharacterization of leases as loans would be recoverable in the form of lower taxes over the remaining term of the investments.

PEPCO HOLDINGS

On August 7, 2008 PHI received a global settlement offer from the IRS with respect to its SILO transactions. PHI is continuing its discussion with the Appeals Office and has not responded to the global settlement offer.

IRS Mixed Service Cost Issue

During 2001, Pepco, DPL, and ACE changed their methods of accounting with respect to capitalizable construction costs for income tax purposes. The change allowed the companies to accelerate the deduction of certain expenses that were previously capitalized and depreciated. 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 believed would be acceptable to the IRS.

At the same time as the proposed regulations were released, the IRS issued Revenue Ruling 2005-53, which was 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 included in the 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. In June 2008, PHI received from the Appeals Office an offer of settlement pertaining to each of Pepco, DPL and ACE for the tax years 2001 through 2004. PHI is substantially in agreement with this proposed settlement. Based on the terms of the proposal, PHI expects the final settlement amount to be less than the $121 million previously deposited.

There was no further correspondence on this issue between the Appeals Office and the Company during the quarter ended September 30, 2008. On the basis of the tentative settlement, PHI updated its estimated liability related to mixed service costs and as a result, recorded a net reduction in its liability for unrecognized tax benefits of $18.7 million and recognized after-tax interest income of $7.2 million. All of the adjustments related to the tentative settlement were recorded in the quarter ended June 30, 2008, and no additional interest or adjustments to the unrecognized tax benefits were recorded during the quarter ended September 30, 2008.

PEPCO HOLDINGS

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 September 30, 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 were as follows:

	Guarantor
		PHI		DPL		ACE		Other		Total
	(Millions of dollars)
Energy marketing obligations of Conectiv Energy (a)	$	174.0	$	-	$	-	$	-	$	174.0
Energy procurement obligations of Pepco Energy Services (a)		199.0		-		-		-		199.0
Guaranteed lease residual values (b)		-		3.5		2.7		.8		7.0
Other (c)		1.8		-		-		1.0		2.8
Total	$	374.8	$	3.5	$	2.7	$	1.8	$	382.8

(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 September 30, 2008, obligations under the guarantees were approximately $7.0 million. Assets leased under agreements subject to residual value guarantees are typically for periods ranging from 2 years to 10 years. Historically, payments under the guarantees have not been made by the guarantor as, under normal conditions, the contract runs to full term at which time the residual value is minimal. As such, Pepco Holdings believes the likelihood of payment being required under the guarantee is remote.
(c)	Other guarantees consist of:

	·	Pepco Holdings has guaranteed a subsidiary building lease of $1.8 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 September 30, 2008, the guarantees cover the remaining $1.0 million in rental obligations.

Pepco Holdings and certain of its subsidiaries have entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These indemnification agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in 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.

PEPCO HOLDINGS

Dividends

On October 23, 2008, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable December 31, 2008, to shareholders of record on December 10, 2008.

(14) 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.

Cash Flow Hedges

For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.

The table below provides detail on effective cash flow hedges under SFAS No. 133 included in PHI’s Consolidated Balance Sheet as of September 30, 2008. Under SFAS No. 133, cash flow hedges are marked-to-market on the balance sheet with corresponding adjustments to Accumulated Other Comprehensive Income. The data in the table indicate the magnitude of the effective cash flow hedges by hedge type (i.e., 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 September 30, 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
Energy Commodity Activities	$	(87.1)	$	(69.5)	58 months
Interest Rate		(26.3)		(3.3)	287 months
Total	$	(113.4)	$	(72.8)

(a)	Accumulated Other Comprehensive Income as of September 30, 2008, includes a $(10.3) million balance related to minimum pension liability. This balance is not included in this table as it is not a cash flow hedge.

PEPCO HOLDINGS

The following table shows the pre-tax gain (loss) recognized in earnings for cash flow hedge ineffectiveness for the three and nine months ended September 30, 2008 and 2007 and where they were reported in PHI’s Consolidated Statements of Earnings during the periods.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(Millions of dollars)
Operating Revenue	$	.6	$	(.4)	$	1.9	$	(1.1)
Fuel and Purchased Energy Expenses		(11.9)		(.2)		(2.7)		(.2)
Total	$	(11.3)	$	(.6)	$	(.8)	$	(1.3)

For the three and nine months ended September 30, 2008, $6.0 million and $.3 million, respectively, in losses were reclassified from Other Comprehensive Income (OCI) to earnings because the forecasted hedged transactions were deemed no longer probable. For the three and nine months ended September 30, 2007, a $.2 million and $.1 million loss, respectively, was reclassified from OCI to earnings because the forecasted hedged transactions were deemed no longer probable.

Fair Value Hedges

In connection with their energy commodity activities, the Competitive Energy businesses designate certain derivatives as fair value hedges. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings.

The net pre-tax gains (losses) recognized during the three and nine months ended September 30, 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:

	Three Months Ended September 30,				Nine Months Ended September 30,
		2008		2007		2008		2007
	(Millions of dollars)
Gains (Losses) on Derivative Instruments	$	21.6	$	6.0	$	(13.4)	$	4.6
(Losses) Gains on Hedged Items		(18.5)		(5.7)		14.0		(4.6)

Other Derivative Activity

In connection with their energy commodity activities, the Competitive Energy businesses hold certain derivatives that do not qualify as hedges. Under SFAS No. 133, these derivatives are recorded at fair value 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:

PEPCO HOLDINGS

Energy Commodity Activities (a)	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(Millions of dollars)
Realized Gains (Losses)	$	1.1	$	(18.9)	$	25.9	$	6.2
Unrealized Gains (Losses)		4.3		6.5		26.8		(1.6)
Total	$	5.4	$	(12.4)	$	52.7	$	4.6

(a)	Includes zero and $.5 million of ineffective fair value hedge gains for the three and nine months ended September 30, 2007, respectively.

As indicated in 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:

	September 30, 2008		December 31, 2007
	(Millions of dollars)

Cash collateral pledged to counterparties with the right to reclaim	$	119.8	$	-
Cash collateral received from counterparties with the obligation to return		65.4		-

As of September 30, 2008 and December 31, 2007, PHI had no cash collateral pledged or received related to derivatives accounted for at fair value that was not eligible for offset under master netting arrangements.

THIS PAGE INTENTIONALLY LEFT BLANK.

PEPCO

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
		2008		2007		2008		2007
		(Millions of dollars)

Operating Revenue	$	727.7	$	693.6	$	1,791.1	$	1,695.2

Operating Expenses
Fuel and purchased energy		431.9		404.0		1,033.2		964.8
Other operation and maintenance		79.9		78.4		226.9		220.7
Depreciation and amortization		35.2		33.0		104.4		116.9
Other taxes		79.8		80.0		218.8		220.3
Effect of settlement of Mirant bankruptcy claims		-		(33.4)		-		(33.4)
Gain on sale of assets		-		-		-		(.6)
Total Operating Expenses		626.8		562.0		1,583.3		1,488.7

Operating Income		100.9		131.6		207.8		206.5

Other Income (Expenses)
Interest and dividend income		1.9		2.8		8.1		3.6
Interest expense		(23.3)		(20.9)		(70.1)		(57.7)
Other income		2.0		2.6		7.0		9.1
Other expenses		(1.2)		(.2)		(1.5)		(.4)
Total Other Expenses		(20.6)		(15.7)		(56.5)		(45.4)

Income Before Income Tax Expense		80.3		115.9		151.3		161.1

Income Tax Expense		34.8		31.3		59.2		49.8

Net Income		45.5		84.6		92.1		111.3

Retained Earnings at Beginning of Period		623.5		555.5		596.9		559.7

Dividends Paid to Pepco Holdings		(44.0)		(45.0)		(64.0)		(74.0)

Cumulative Effect Adjustment Related to the Implementation of FIN 48		-		-		-		(1.9)

Retained Earnings at End of Period	$	625.0	$	595.1	$	625.0	$	595.1

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

PEPCO

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

ASSETS		September 30, 2008		December 31, 2007
	(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$	38.6	$	19.0
Restricted cash equivalents			20.9		1.2
Accounts receivable, less allowance for uncollectible accounts of $13.7 million and $12.5 million, respectively			404.3		343.5
Materials and supplies - at average cost			46.5		45.4
Prepayments of income taxes			99.3		93.4
Prepaid expenses and other			34.4		15.1
Total Current Assets			644.0		517.6

INVESTMENTS AND OTHER ASSETS
Regulatory assets			176.2		178.5
Prepaid pension expense			144.6		152.0
Investment in trust			27.5		26.5
Income taxes receivable			173.7		171.2
Restricted cash equivalents			100.4		417.3
Other			67.3		75.4
Total Investments and Other Assets			689.7		1,020.9

PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			5,542.0		5,368.9
Accumulated depreciation			(2,345.7)		(2,274.4)
Net Property, Plant and Equipment			3,196.3		3,094.5

TOTAL ASSETS		$	4,530.0	$	4,633.0

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

PEPCO

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

LIABILITIES AND SHAREHOLDER’S EQUITY		September 30, 2008		December 31, 2007
	(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt		$	167.7	$	179.9
Current maturities of long-term debt			100.0		128.0
Accounts payable and accrued liabilities			192.6		201.7
Accounts payable to associated companies			64.5		75.8
Capital lease obligations due within one year			6.2		6.0
Taxes accrued			102.0		90.1
Interest accrued			33.2		17.0
Liabilities and accrued interest related to uncertain tax positions			37.8		67.8
Other			116.2		88.9
Total Current Liabilities			820.2		855.2

DEFERRED CREDITS
Regulatory liabilities			235.1		542.4
Deferred income taxes, net			673.3		619.2
Investment tax credits			11.0		12.5
Other postretirement benefit obligation			56.6		57.4
Income taxes payable			134.7		129.0
Other			66.0		70.1
Total Deferred Credits			1,176.7		1,430.6

LONG-TERM LIABILITIES
Long-term debt			1,194.7		1,111.7
Capital lease obligations			102.0		105.2
Total Long-Term Liabilities			1,296.7		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			625.0		596.9
Total Shareholder’s Equity			1,236.4		1,130.3

TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY		$	4,530.0	$	4,633.0

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

PEPCO

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

		Nine Months Ended September 30,
			2008		2007
	(Millions of dollars)
OPERATING ACTIVITIES
Net income		$	92.1	$	111.3
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization			104.4		116.9
Deferred income taxes			60.4		15.8
Effect of settlement of Mirant bankruptcy claims			-		(33.4)
Gain on sale of assets			-		(.6)
Proceeds from settlement of Mirant bankruptcy claims			-		507.2
Reimbursements to Mirant					(108.3)
Changes in restricted cash related to Mirant settlement			316.9		(416.7)
Changes in:
Accounts receivable			(60.7)		(116.4)
Regulatory assets and liabilities			(314.4)		(18.3)
Accounts payable and accrued liabilities			13.8		74.2
Interest and taxes accrued			(14.9)		40.2
Other changes in working capital			(9.1)		(15.1)
Net other operating			3.9		6.0
Net Cash From Operating Activities			192.4		162.8

INVESTING ACTIVITIES
Net investment in property, plant and equipment			(201.9)		(194.3)
Proceeds from settlement of Mirant bankruptcy claims representing reimbursement for investment in property, plant and equipment			-		15.0
Changes in restricted cash equivalents			(19.7)		-
Net other investing activities			(1.8)		(2.4)
Net Cash Used By Investing Activities			(223.4)		(181.7)

FINANCING ACTIVITIES
Dividends paid to Pepco Holdings			(64.0)		(74.0)
Capital contribution from Pepco Holdings			78.0		-
Issuances of long-term debt			250.0		-
Reacquisition of long-term debt			(187.5)		(35.0)
(Repayments) issuances of short-term debt, net			(12.3)		127.0
Net other financing activities			(13.6)		(1.0)
Net Cash From Financing Activities			50.6		17.0

Net Increase (Decrease) in Cash and Cash Equivalents			19.6		(1.9)
Cash and Cash Equivalents at Beginning of Period			19.0		12.4

CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	38.6	$	10.5

NON-CASH ACTIVITIES
Asset retirement obligations associated with removal costs transferred to regulatory liabilities		$	6.3	$	3.9

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for income taxes (includes payments to PHI for Federal income taxes)		$	40.5	$	6.6

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).

Impact of the Current Capital and Credit Market Disruptions

The recent disruptions in the capital and credit markets have had an impact on Pepco’s business. While these conditions have required Pepco to make certain adjustments in its financial management activities, Pepco believes that it currently has sufficient liquidity to fund its operations and meet its financial obligations. These market conditions, should they continue, however, could have a negative effect on Pepco’s financial condition, results of operations and cash flows.

Liquidity Requirements

Pepco depends on access to the capital and credit markets to meet its liquidity and capital requirements. To meet its liquidity requirements, Pepco historically has relied on the issuance of commercial paper and short-term notes and on bank lines of credit to supplement internally generated cash from operations. Pepco’s primary credit source is PHI’s $1.5 billion syndicated credit facility, under which Pepco can borrow funds, obtain letters of credit and support the issuance of commercial paper in an amount up to $500 million (subject to the limitation that the total utilization by Pepco, DPL and ACE cannot exceed $625 million). This facility is in effect until May 2012 and consists of commitments from 17 lenders, no one of which is responsible for more than 8.5% of the total commitment.

Due to the capital and credit market disruptions, the market for commercial paper in September and October 2008 has been severely restricted for most companies. As a result, Pepco has not been able to issue commercial paper on a day-to-day basis either in amounts or with maturities that it typically has required for cash management purposes. Given its restricted access to the commercial paper market and the uncertainty in the credit markets generally, Pepco has borrowed $200 million under the credit facility to create a cash reserve for future short-term operating needs. After giving effect to outstanding letters of credit and commercial paper, PHI’s utility subsidiaries have an aggregate of $308 million in combined cash and borrowing capacity under the credit facility as of September 30, 2008. During the month of October 2008, the average daily amount of the combined cash and borrowing capacity of PHI’s utility subsidiaries was $286 million and ranged from a low of $178 million to a high of $350 million.

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To address the challenges posed by the current capital and credit market environment and to ensure that it will continue to have sufficient access to cash to meet its liquidity needs, Pepco has identified a number of cash and liquidity conservation measures, including opportunities to defer capital expenditures due to lower than anticipated growth. Several measures to reduce expenditures have been taken. Additional measures could be undertaken if conditions warrant.

Due to the financial market conditions, which have caused uncertainty of short-term funding, Pepco has filed applications with the Maryland Public Service Commission and the District of Columbia Public Service Commission for authority to issue up to $250 million in long-term debt securities no later than June 15, 2009, with the proceeds to be used to refund short-term debt incurred to finance utility construction and operations on a temporary basis and incurred to fund the temporary repurchase of tax-exempt auction rate securities.

Pension and Postretirement Benefit Plans

Pepco participates in pension and postretirement benefit plans sponsored by PHI for its employees. While the plans have not experienced any significant impact in terms of liquidity or counterparty exposure due to the disruption of the capital and credit markets, the recent stock market declines have caused a decrease in the market value of benefit plan assets over the nine months ended September 30, 2008.

(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 September 30, 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 and nine months ended September 30, 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 was obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (Panda PPA), Pepco potentially assumed the variability in the operations of the plants related to the Panda PPA and therefore had a variable interest in the entity.

During the third quarter of 2008, Pepco transferred the Panda PPA to Sempra Energy Trading LLP. Net purchase activities with the counterparty to the Panda PPA for the three

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months ended September 30, 2008 and 2007 were approximately $17 million and $24 million, respectively. Net purchase activities with the counterparty to the Panda PPA for the nine months ended September 30, 2008 and 2007 were approximately $59 million and $67 million, respectively. See Note (10) “Commitments and Contingencies — Regulatory and Other Matters — Proceeds from Settlement of Mirant Bankruptcy Claims.”

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $67.3 million and $68.5 million for the three months ended September 30, 2008 and 2007, respectively, and $182.6 million and $185.2 million for the nine months ended September 30, 2008 and 2007, respectively.

Reclassifications and Adjustments

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

In the second quarter of 2008, Pepco recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to February 2005 where late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $3.3 million. In the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the Long-Term Incentive Plan which resulted in an understatement of Pepco’s stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in Pepco’s Other Operation and Maintenance expenses for the three and nine months ended September 30, 2008 of $3.2 million. These adjustments are not considered material either individually or in the aggregate.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 157, "Fair Value Measurements" (SFAS No. 157)

In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (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 to other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. Under 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 in the most advantageous market using the best available information. The provisions of SFAS No. 157 were effective for financial statements beginning January 1, 2008 for Pepco.

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 removed fair value measurement for the recognition and measurement of lease transactions from the scope of SFAS No. 157. The

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effective date of SFAS No. 157-1 was for financial statement periods beginning January 1, 2008 for Pepco.

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 required 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.” Pepco is currently evaluating the impact of SFAS No. 157-2 on non-financial assets (including liabilities); however, Pepco does not anticipate that the application of SFAS No. 157 to its other non-financial assets and non-financial liabilities would materially affect its overall financial condition, results of operations or cash flows.

On September 30, 2008, the Securities and Exchange Commission and FASB issued guidance on fair value measurements, which was amplified on October 10, 2008 by the FASB in FSP Financial Accounting Standards (FAS) 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active.” This guidance clarifies the application of SFAS No. 157 to assets in an inactive market and illustrates how to determine the fair value of a financial asset in an inactive market. The guidance was effective beginning with the September 30, 2008 reporting period for Pepco and has not had a material impact on Pepco’s results.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities–including an Amendment of FASB Statement No. 115” (SFAS No. 159)

On February 15, 2007, the FASB issued SFAS No. 159, which permits entities to elect to measure eligible financial instruments at fair value. SFAS No. 159 applies to other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. On January 1, 2008, Pepco did not 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” (SFAS No. 141 (R))

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deferred tax benefits that are realizable because of a business combination either in income from continuing operations or directly in contributed capital, depending on the circumstances.

SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009 for Pepco. Pepco is currently evaluating the potential impact SFAS No. 141(R) may have on its overall financial condition, results of operations, cash flows and footnote disclosure requirements.

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

SFAS No. 160 is effective prospectively for financial statement reporting periods beginning January 1, 2009 for Pepco, 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 and footnote disclosure requirements.

SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162)

SFAS No. 162 will be effective for Pepco as of November 15, 2008. The FASB believes that the application of SFAS No. 162 is not expected to result in a change in accounting; however, if it does, the accounting change must be reported as a change in accounting principle under SFAS No. 154, “Accounting Changes and Error Corrections.” Pepco is currently evaluating the impact SFAS No. 162 may have on its overall financial condition, results of operations, cash flows and footnote disclosure requirements.

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FSP APB 14-1, “Accounting for Convertible Debt Instruments that may be Settled in Cash upon Conversion (Including Partial Cash Settlement)” (FSP APB 14-1)

On May 9, 2008, the FASB issued FSP Accounting Principles Board (APB) 14-1, which addresses the accounting for convertible debt securities that, upon conversion, may be settled by the issuer fully or partially in cash unless the embedded conversion option is required to be separately accounted for as a derivative under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133).

FSP APB 14-1 is effective for financial statement reporting periods beginning January 1, 2009 for Pepco and shall be applied retrospectively to all periods presented. Pepco does not currently have any convertible debt instruments outstanding; however, these types of instruments may be considered for financing future endeavors.

EITF Issue No. 07-05, “Determining Whether an Instrument (or Embedded Feature) is Indexed to an Entity’s Own Stock” (EITF 07-05)

On June 25, 2008, the FASB ratified Emerging Issues Task Force (EITF) 07-05, which provides a two-step approach for determining whether an equity-linked financial instrument (or embedded feature) that has all of the characteristics of a derivative in paragraph 6-9 of SFAS No. 133 qualifies for the first part of the scope exception from derivative accounting in paragraph 11(a) of SFAS No. 133 for being “indexed to an entity’s own stock.” This issue also applies to any freestanding financial instrument that is settled in an entity’s own stock, regardless of whether an instrument has all the characteristics of a derivative. In addition, it includes derivative instruments that fall within the scope of EITF Issue 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company's Own Stock.” This issue supersedes EITF Issue 01-06, “The Meaning of ‘Indexed to a Company’s Own Stock’” and does not apply to share-based payment awards within the scope of SFAS No. 123(R), “Share-Based Payments.”

EITF 07-05 applies to financial statement periods beginning January 1, 2009 for Pepco to any outstanding instruments. The cumulative effect of the change in accounting principle shall be recognized as an adjustment to the opening balance of retained earnings for that fiscal year in which this issue is initially applied, presented separately. Pepco does not currently have any financial instruments that are indexed to its own stock outstanding; however, these types of instruments may be considered for financing future endeavors.

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FSP FAS 133-1 and FIN 45-4, “Disclosure About Credit Derivatives and Certain Guarantees” (FSP FAS 133-1 and FIN 45-4)

On September 12, 2008, the FASB adopted FSP FAS 133-1 and FASB Interpretation No. (FIN) 45-4, which enhance disclosures by entities that provide credit protection through credit derivatives (including embedded credit derivatives) within the scope of SFAS No. 133, and guarantees within the scope of FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees Indebtedness of Others.” In addition, FSP FAS 133-1 clarifies the Board’s intent on the effective date for SFAS No. 161, “Disclosures about Derivatives Instruments and Hedging Activities.”

For credit derivatives, FSP FAS 133-1 requires disclosure on the nature and fair value of the credit derivative, the approximate term, the reasons for entering the derivative, the events requiring performance, and the current status of the payment/performance risk. It also requires disclosure of the maximum potential amount of future payments without any reduction for possible recoveries under collateral provisions, recourse provisions, or liquidation proceeds. For guarantees, FSP FAS 133-1 requires disclosure on the current status of the payment/performance risk and whether the current status is based on external credit ratings or current internal groupings used to manage risk. If internal groupings are used, then information is required about how the groupings are determined and used for managing risk.

The new disclosures are required starting with financial statement reporting periods ending December 31, 2008 for Pepco. Comparative disclosures are only required for periods ending after initial adoption. Pepco is currently evaluating the impact on its disclosures.

(5) SEGMENT INFORMATION

Pepco has identified its regulated utility business as its only reporting and operating segment based on the provisions of SFAS 131, “Disclosures about Segments of an Enterprise and Related Information.”

(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 September 30, 2008, of $16.1 million includes $6.0 million for Pepco’s allocated share. PHI's pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2008, of $48.3 million includes $18.1 million for Pepco's allocated share.

PHI’s pension and other postretirement net periodic benefit cost for the three months ended September 30, 2007, of $20.5 million includes $5.6 million for Pepco’s allocated share. PHI's pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2007, of $48.4 million includes $16.8 million for Pepco's allocated share.

(7) DEBT

PHI, Pepco, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE) maintain a credit facility to provide for their respective short-term liquidity

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needs. The aggregate borrowing limit under the facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI's credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million.

As a result of severe liquidity constraints in the credit, commercial paper and capital markets during September 2008, Pepco borrowed under the $1.5 billion credit facility. Typically, Pepco issues commercial paper if required to meet its short-term working capital requirements. Given the lack of liquidity in the commercial paper markets, Pepco borrowed under the credit facility to maintain sufficient cash on hand to meet daily short-term operating needs. At September 30, 2008, Pepco borrowed $100 million. The LIBOR-based loan matured during October 2008 and was rolled to November 2008. In October, Pepco borrowed an additional $100 million under the facility.

In September 2008, Pepco repaid at maturity a $25 million short-term loan.

(8) INCOME TAXES

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

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2008		2007		2008		2007

Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	1.6		.9		2.6		2.5
Asset removal costs	(.7)		(.4)		(1.9)		(1.0)
State income taxes, net of federal effect	5.9		5.2		5.9		5.5
Software amortization	.6		.8		1.1		1.5
Tax credits	(.6)		(.7)		(1.0)		(1.1)
Adjustment to prior years’ taxes	1.1		.3		.6		(.2)
Change in estimates and interest related to uncertain and effectively settled tax positions	1.0		.7		(1.8)		(.1)
Maryland state tax refund and interest	(.4)		(16.8)		(1.7)		(12.1)
Deferred tax adjustment	-		2.8		.4		2.0
Other, net	(.2)		(.8)		(.1)		(1.1)

Effective Income Tax Rate	43.3	%	27.0	%	39.1	%	30.9	%

Pepco’s effective tax rates for the three months ended September 30, 2008 and 2007 were 43.3% and 27.0%, respectively. The increase in the effective tax rate primarily resulted from the receipt of the Company’s Maryland state tax refund recorded in the third quarter of 2007, the adjustment to prior years’ taxes due to the finalization of the tax return and certain depreciation book/tax differences, partially offset by a deferred tax adjustment recorded in the third quarter of 2007.

Pepco’s effective tax rates for the nine months ended September 30, 2008 and 2007 were 39.1% and 30.9%, respectively. The increase in the effective tax rate primarily resulted from receipt of the Company’s Maryland state tax refund recorded in the third quarter of 2007 and

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interest recorded in the second quarter of 2008 of $3.5 million ($2.2 million after-tax) relating to the Maryland state tax refund. This increase is partially offset by interest related to uncertain and effectively settled tax positions and a deferred tax adjustment recorded in the third quarter of 2007.

During the second quarter 2008, Pepco reached a tentative settlement with the Internal Revenue Service (IRS) concerning the treatment of mixed service costs for income tax purposes during the period 2001 to 2004. See “Commitments and Contingencies — Regulatory and Other Matters — IRS Mixed Service Cost Issue” in Note (10). On the basis of the tentative settlement, Pepco updated its estimated liability related to mixed service costs and as a result, recorded a net reduction in its liability for unrecognized tax benefits of $15.8 million and recognized after-tax interest income of $2.7 million in the second quarter of 2008.

(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, 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:

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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.

The following table sets forth by level within the fair value hierarchy Pepco's financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 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.

	Fair Value Measurements at Reporting Date Using
	(Millions of dollars)
Description	September 30, 2008		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)

ASSETS
Cash equivalents	$	121.2	$	121.2	$	-	$	-
Executive deferred compensation plan assets		65.7		10.3		39.7		15.7
	$	186.9	$	131.5	$	39.7	$	15.7

LIABILITIES
Executive deferred compensation plan liabilities	$	13.7	$	-	$	13.7	$	-
	$	13.7	$	-	$	13.7	$	-

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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		2.8
Included in other comprehensive income		-
Purchases and issuances		(3.1)
Settlements		-
Transfers in and/or out of Level 3		-
Ending balance as of September 30, 2008	$	15.7


Gains or (losses) (realized and unrealized) included in earnings for the period above are reported in Other Operation and Maintenance Expense as follows:	Other Operation and Maintenance Expense

Total gains included in earnings for the period above	$	2.8

Change in unrealized gains relating to assets still held at reporting date	$	2.8

(10) COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Proceeds from Settlement of Mirant Bankruptcy Claims

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Rate Proceedings

In electric service distribution base rate cases filed 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 increases rates if actual distribution revenues fall below the level approved by the applicable commission and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, the utility collects its authorized revenues for distribution deliveries. As a consequence, a BSA “decouples” revenue from unit sales 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 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

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August 21, 2008, the DCPSC issued an order concluding that it has the necessary statutory authority to implement the BSA proposal and further evidentiary proceedings are warranted to determine whether the BSA is just and reasonable.

Maryland

In July 2007, the MPSC issued an order in Pepco’s electric service distribution rate case, 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 July 19, 2008, pending a Phase II proceeding in which the MPSC considered the results of an audit of Pepco’s cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates was required. On July 18, 2008, the MPSC issued an order covering the Phase II proceedings, denying any further adjustment to Pepco’s rates, thus making permanent the rate increases approved in the July 2007 order. The MPSC also issued an order on August 4, 2008, further explaining its July 18 order.

On August 18, 2008, Pepco filed a general notice of appeal of both the July 18 and August 4 orders (under Maryland rules, a petitioner is not required to specify the basis of the appeal in the notice of appeal). The appeal was filed in the Circuit Court for Montgomery County, Maryland and included a motion to transfer the proceeding to Cecil County. The MPSC filed a motion to transfer the proceedings from the Circuit Court of Montgomery County to the Circuit Court for Baltimore City. No action has been taken in Montgomery County.

Federal Energy Regulatory Commission

On August 18, 2008, Pepco submitted an application with the Federal Energy Regulatory Commission (FERC) for incentive rate treatments in connection with PHI’s 230-mile, 500-kilovolt Mid-Atlantic Power Pathway Project (the MAPP Project). The application requested that FERC include all of Pepco’s Construction Work in Progress in rate base, an ROE adder of 150 basis points and the recovery of prudently incurred costs in the event the project is abandoned or terminated for reasons beyond Pepco’s control. On October 31, 2008, FERC granted unanimous approval of the requested rate incentives.

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 September 30, 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. Other issues in the divestiture proceeding deal with

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the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.

Pepco believes that a sharing of EDIT and ADITC would violate the IRS normalization rules. Under these rules, Pepco could not transfer the EDIT and the ADITC benefit to customers more quickly than on a straight line basis over the book life of the related assets. Since the assets are no longer owned by Pepco, there is no book life over which the EDIT and ADITC can be returned. If Pepco were required to share EDIT and ADITC and, as a result, the normalization rules were violated, Pepco would be unable to use accelerated depreciation on District of Columbia allocated or assigned property. In addition to sharing with customers the generation-related EDIT and ADITC balances, Pepco 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 September 30, 2008), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3.5 million as of September 30, 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.

Maryland

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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 September 30, 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 September 30, 2008), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($6.3 million as of September 30, 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.

General Litigation

Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed. As a result of two motions to dismiss,

PEPCO

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 September 30, 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, Pepco believes the amounts claimed by the remaining plaintiffs are greatly exaggerated. The amount of total liability, if any, and any related insurance recovery cannot be determined at this time; however, based on information and relevant circumstances known at this time, Pepco does not believe these suits will have a material adverse effect on its financial position, results of operations or cash flows. However, if an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco’s financial position, results of operations or cash flows.

Environmental Litigation

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

Carolina Transformer Site. In August 2006, the 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 early 2008, EPA, the PRP group and the State of North Carolina entered into a settlement agreement under which (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 covenanted not to sue or bring administrative action against Pepco for response costs at the site, (iii) other PRP group members released all rights for cost recovery or contribution claims they may have against Pepco, and (iv) Pepco released all rights for cost recovery or contribution claims that it may have against other parties settling with EPA and the State of North Carolina. On September 24, 2008, the U.S. District Court for the Eastern District of North Carolina entered a consent decree which resolves Pepco’s liability at the site.

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

PEPCO

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 believed would be acceptable to the IRS.

At the same time as the proposed regulations were released, the IRS issued Revenue Ruling 2005-53, which was 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 included in the audit matters relating to the 2001 and 2002 audits pending before the U.S. Office of Appeals of the IRS (Appeals Office).

In February 2006, PHI paid approximately $121 million of taxes (a portion of which is attributable to Pepco) 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. In June 2008, PHI received from the Appeals Office an offer of settlement pertaining to Pepco for the tax years 2001 through 2004. Pepco is substantially in agreement with this proposed settlement. Based on the terms of the proposal, Pepco expects the final settlement amount to be less than the amount previously deposited.

There was no further correspondence on this issue between the Appeals Office and Pepco during the quarter ended September 30, 2008. On the basis of the tentative settlement, Pepco updated its estimated liability related to mixed service costs and as a result, recorded a net reduction in its liability for unrecognized tax benefits of $15.8 million and recognized after-tax interest income of $2.7 million. All of the adjustments related to the tentative settlement were recorded in the quarter ended June 30, 2008, and no additional interest or adjustments to the unrecognized tax benefits were recorded during the quarter ended September 30, 2008.

(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. PHI Service Company costs directly charged or allocated to Pepco for the three months ended September 30, 2008 and 2007 were approximately $39.1 million and $33.0 million, respectively. PHI Service Company costs directly charged or allocated to Pepco for the nine months ended September 30, 2008 and 2007 were approximately $108.9 million and $94.5 million, respectively.

PEPCO

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 September 30, 2008 and 2007 were approximately $3.3 million and $6.9 million, respectively. Amounts charged to Pepco by these companies for the nine months ended September 30, 2008 and 2007 were approximately $8.6 million and $22.9 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 September 30,				For the Nine Months Ended September 30,
	2008		2007		2008		2007
	(Millions of dollars)
Income (Expense)
Intercompany power purchases - Conectiv Energy Supply (a)	$	(.1)	$	(19.2)	$	(22.7)	$	(48.9)	(
Intercompany lease transactions (b)	$	-	$	.1	$	(.1)	$	(.3)

(a)	Included in fuel and purchased energy.

(b)	Included in other operation and maintenance.

As of September 30, 2008 and December 31, 2007, Pepco had the following balances on its Balance Sheets due (to)/from related parties:

	September 30, 2008	December 31, 2007
Asset (Liability)	(Millions of dollars)
Payable to Related Party (current)
PHI Service Company	$(19.9)	$(16.9)
Conectiv Energy Supply	-	(5.8)
Pepco Energy Services (a)	(44.5)	(53.0)

The items listed above are included in the “Accounts payable to associated companies” balance on the Balance Sheet of $64.5 million and $75.8 million at September 30, 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)	$30.2	$(95.9)

Money Pool Interest Accrued (included in interest accrued)	-	(.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.

THIS PAGE INTENTIONALLY LEFT BLANK.

DPL

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
		2008		2007		2008		2007
		(Millions of dollars)
Operating Revenue
Electric	$	348.4	$	356.1	$	931.8	$	929.8
Natural Gas		53.0		43.3		251.7		221.2
Total Operating Revenue		401.4		399.4		1,183.5		1,151.0

Operating Expenses
Fuel and purchased energy		242.5		253.3		629.2		656.6
Gas purchased		43.4		33.9		199.9		171.0
Other operation and maintenance		63.1		52.0		173.4		151.4
Depreciation and amortization		18.3		18.6		54.4		55.9
Other taxes		8.9		9.9		26.4		27.7
Gain on sale of assets		-		(.4)		(3.1)		(1.0)
Total Operating Expenses		376.2		367.3		1,080.2		1,061.6

Operating Income		25.2		32.1		103.3		89.4

Other Income (Expenses)
Interest and dividend income		.3		.1		1.9		.8
Interest expense		(9.3)		(11.2)		(27.5)		(32.6)
Other income		.6		.9		2.0		2.0
Other expense		-		-		-		-
Total Other Expenses		(8.4)		(10.2)		(23.6)		(29.8)

Income Before Income Tax Expense		16.8		21.9		79.7		59.6

Income Tax Expense		5.5		10.8		26.0		23.9

Net Income		11.3		11.1		53.7		35.7

Retained Earnings at Beginning of Period		432.2		423.5		431.8		426.4

Dividends Paid to Parent		-		-		(42.0)		(27.0)

Preferred Stock Redemption		-		-		-		(.6)

Cumulative Effect Adjustment Related to the Implementation of FIN 48		-		-		-		.1

Retained Earnings at End of Period	$	443.5	$	434.6	$	443.5	$	434.6

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

DPL

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

ASSETS		September 30, 2008		December 31, 2007
	(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$	8.2	$	11.4
Restricted cash equivalents			12.0		3.8
Accounts receivable, less allowance for uncollectible accounts of $11.2 million and $8.0 million, respectively			197.0		194.9
Fuel, materials and supplies - at average cost			51.7		45.3
Prepayments of income taxes			54.7		56.1
Prepaid expenses and other			16.6		15.2
Total Current Assets			340.2		326.7

INVESTMENTS AND OTHER ASSETS
Goodwill			8.0		8.0
Regulatory assets			211.8		224.6
Prepaid pension expense			182.6		178.1
Other			40.1		35.3
Total Investments and Other Assets			442.5		446.0

PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			2,628.0		2,615.8
Accumulated depreciation			(826.5)		(828.8)
Net Property, Plant and Equipment			1,801.5		1,787.0

TOTAL ASSETS		$	2,584.2	$	2,559.7

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

DPL

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

LIABILITIES AND SHAREHOLDER’S EQUITY		September 30, 2008		December 31, 2007
	(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt		$	353.9	$	286.2
Current maturities of long-term debt			-		22.6
Accounts payable and accrued liabilities			90.7		104.7
Accounts payable to associated companies			39.0		54.0
Taxes accrued			12.7		8.2
Interest accrued			9.2		5.7
Liabilities and accrued interest related to uncertain tax positions			13.3		34.1
Other			68.8		60.5
Total Current Liabilities			587.6		576.0

DEFERRED CREDITS
Regulatory liabilities			280.0		275.5
Deferred income taxes, net			452.9		410.1
Investment tax credits			8.4		9.0
Above-market purchased energy contracts and other electric restructuring liabilities			19.5		21.1
Other			52.4		65.2
Total Deferred Credits			813.2		780.9

LONG-TERM LIABILITIES
Long-term debt			436.0		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			443.5		431.8
Total Shareholder’s Equity			747.4		673.4

TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY		$	2,584.2	$	2,559.7

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

DPL

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,
		2008		2007
	(Millions of dollars)
OPERATING ACTIVITIES
Net income	$	53.7	$	35.7
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		54.4		55.9
Gain on sale of assets		(3.1)		(1.0)
Investment tax credit adjustments		(.6)		(.6)
Deferred income taxes		41.0		8.9
Changes in:
Accounts receivable		(24.7)		(15.1)
Regulatory assets and liabilities		32.1		1.7
Accounts payable and accrued liabilities		(21.5)		23.5
Interest and taxes accrued		(21.5)		(.5)
Other changes in working capital		(10.3)		(5.3)
Net other operating		(1.4)		.6
Net Cash From Operating Activities		98.1		103.8

INVESTING ACTIVITIES
Net investment in property, plant and equipment		(108.5)		(92.4)
Changes in restricted cash equivalents		(8.2)		(2.9)
Proceeds from sale of assets		50.3		.4
Net other investing activities		(.4)		(.4)
Net Cash Used By Investing Activities		(66.8)		(95.3)

FINANCING ACTIVITIES
Dividends paid to Parent		(42.0)		(27.0)
Capital contribution from Parent		62.3		-
Issuance of long-term debt		150.0		-
Reacquisition of long-term debt		(116.0)		(64.7)
(Repayments) issuances of short-term debt, net		(82.3)		92.6
Redemption of preferred stock		-		(18.2)
Net other financing activities		(6.5)		6.7
Net Cash Used By Financing Activities		(34.5)		(10.6)

Net Decrease in Cash and Cash Equivalents		(3.2)		(2.1)
Cash and Cash Equivalents at Beginning of Period		11.4		8.2

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	8.2	$	6.1

NON-CASH ACTIVITIES
Asset retirement obligations associated with removal costs transferred to regulatory liabilities	$	(1.1)	$	4.7
Conversion of long-term debt to short-term debt	$	150.0	$	-

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for income taxes (includes payments to PHI for Federal income taxes)	$	8.1	$	4.0

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

DPL

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).

In January 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 that became known within six months after the January 2, 2008 closing date. The allowance period for A&N and/or ODEC to notify DPL has passed and no notification was made with respect to the discovery of additional pre-closing liabilities. A&N delayed final payment of approximately $3.5 million, which was due on June 2, 2008, due to a dispute in the final true-up amounts. On October 21, 2008, DPL and A&N entered into a Settlement Agreement pursuant to which A&N has paid $3.5 million to DPL, and an additional $.5 million has been distributed to DPL pursuant to an escrow agreement.

Impact of the Current Capital and Credit Market Disruptions

The recent disruptions in the capital and credit markets have had an impact on DPL’s business. While these conditions have required DPL to make certain adjustments in its financial management activities, DPL believes that it currently has sufficient liquidity to fund its operations and meet its financial obligations. These market conditions, should they continue, however, could have a negative effect on DPL’s financial condition, results of operations and cash flows.

DPL

Liquidity Requirements

DPL depends on access to the capital and credit markets to meet its liquidity and capital requirements. To meet its liquidity requirements, DPL historically has relied on the issuance of commercial paper and short-term notes and on bank lines of credit to supplement internally generated cash from operations. DPL’s primary credit source is PHI’s $1.5 billion syndicated credit facility, under which DPL can borrow funds, obtain letters of credit and support the issuance of commercial paper in an amount up to $500 million (subject to the limitation that the total utilization by Pepco, DPL and ACE cannot exceed $625 million). This facility is in effect until May 2012 and consists of commitments from 17 lenders, no one of which is responsible for more than 8.5% of the total commitment.

Due to the capital and credit market disruptions, the market for commercial paper in September and October 2008 has been severely restricted for most companies. As a result, DPL has not been able to issue commercial paper on a day-to-day basis either in amounts or with maturities that it typically has required for cash management purposes. Given its restricted access to the commercial paper market and the uncertainty in the credit markets generally, DPL borrowed $150 million under the credit facility to create a cash reserve for future short-term operating needs. After giving effect to outstanding letters of credit and commercial paper, PHI’s utility subsidiaries have an aggregate of $308 million in combined cash and borrowing capacity under the credit facility as of September 30, 2008. During the month of October 2008, the average daily amount of the combined cash and borrowing capacity of PHI’s utility subsidiaries was $286 million and ranged from a low of $178 million to a high of $350 million.

To address the challenges posed by the current capital and credit market environment and to ensure that it will continue to have sufficient access to cash to meet its liquidity needs, DPL has identified a number of cash and liquidity conservation measures, including opportunities to defer capital expenditures due to lower than anticipated growth. Several measures to reduce expenditures have been taken. Additional measures could be undertaken if conditions warrant.

Due to the financial market conditions, which have caused uncertainty of short-term funding, DPL has filed applications with the Maryland Public Service Commission and the Delaware Public Service Commission for authority to issue up to $250 million in long-term debt securities no later than June 15, 2009, with the proceeds to be used to refund short-term debt incurred to finance utility construction and operations on a temporary basis and incurred to fund the temporary repurchase of tax-exempt auction rate securities.

Pension and Postretirement Benefit Plans

DPL participates in several of the pension and postretirement benefit plans sponsored by PHI and its subsidiaries for their employees. While the plans have not experienced any significant impact in terms of liquidity or counterparty exposure due to the disruption of the capital and credit markets, the recent stock market declines have caused a decrease in the market value of benefit plan assets over the nine months ended September 30, 2008.

DPL

(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 September 30, 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 and nine months ended September 30, 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 $4.3 million and $3.7 million for the three months ended September 30, 2008 and 2007, respectively, and $11.4 million and $9.9 million for the nine months ended September 30, 2008 and 2007, respectively.

Reclassifications and Adjustments

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

In the third quarter of 2008, DPL recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to May 2006 where late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the three and nine months ended September 30, 2008 of $3.8 million and $2.8 million, respectively. In the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the Long-Term Incentive Plan which resulted in an understatement of DPL’s stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in DPL’s Other Operation and Maintenance expenses for the three and nine months ended September 30, 2008 of $1.8 million. These adjustments are not considered material either individually or in the aggregate.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 157, "Fair Value Measurements" (SFAS No. 157)

DPL

measurements. SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. Under 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 in the most advantageous market using the best available information. The provisions of SFAS No. 157 were effective for financial statements beginning January 1, 2008 for DPL.

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 required 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.” DPL is currently evaluating the impact of SFAS No. 157-2 on non-financial assets (including goodwill and liabilities); however, DPL does not anticipate that the application of SFAS No. 157 to its other non-financial assets and non-financial liabilities would materially affect its overall financial condition, results of operations or cash flows.

On September 30, 2008, the Securities and Exchange Commission and FASB issued guidance on fair value measurements, which was amplified on October 10, 2008 by the FASB in FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active.” This guidance clarifies the application of SFAS No. 157 to assets in an inactive market and illustrates how to determine the fair value of a financial asset in an inactive market. The guidance was effective beginning with the September 30, 2008 reporting period for DPL and has not had a material impact on DPL’s results.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities–including an Amendment of FASB Statement No. 115” (SFAS No. 159)

On February 15, 2007, the FASB issued SFAS No. 159, which permits entities to elect to measure eligible financial instruments at fair value. SFAS No. 159 applies to other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. On January 1, 2008, DPL did not elect the fair value option for its eligible financial assets and liabilities.

DPL

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

On April 30, 2007, the FASB issued FSP FASB Interpretation No. (FIN) 39-1 that amended certain portions of FASB Interpretation No. 39 (FIN 39). The FSP replaces the terms “conditional contracts” and “exchange contracts” in FIN 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 FIN 39 to allow for the offsetting of fair value amounts for the right to reclaim cash collateral or receivables, or the obligation to return cash collateral or payables, arising from the same master netting arrangement as the derivative instruments. FSP FIN 39-1 applied to financial statements beginning 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 provided in Note (14) “Use Of Derivatives in Energy and Interest Rate Hedging Activities.” 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” (SFAS No. 141 (R))

SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009 for DPL. DPL is currently evaluating the potential impact SFAS No. 141(R) may have on its overall financial condition, results of operations, cash flows and footnote disclosure requirements.

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

DPL

SFAS No. 160 is effective prospectively for financial statement reporting periods beginning January 1, 2009 for DPL, 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 and footnote disclosure requirements.

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

On March 19, 2008, the FASB issued SFAS No. 161, which changes the disclosure requirements for derivative instruments and hedging activities. Entities will be required to provide qualitative disclosures about derivatives objectives and strategies, gross fair value amounts of gains and losses on derivative instruments which before were optional, disclosure about credit-risk-related contingent features in derivative agreements, and information on the potential effect on an entity’s liquidity from using derivatives.

SFAS No. 161 is effective for financial statement reporting periods beginning January 1, 2009 for DPL. SFAS No. 161 encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption. DPL is currently evaluating the impact SFAS No. 161 may have on its footnote disclosure requirements.

SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162)

SFAS No. 162 will be effective for DPL as of November 15, 2008. The FASB believes that the application of SFAS No. 162 is not expected to result in a change in accounting; however, if it does, the accounting change must be reported as a change in accounting principle under SFAS No. 154, “Accounting Changes and Error Corrections.” DPL is currently evaluating

DPL

the impact SFAS No. 162 may have on its overall financial condition, results of operations, cash flows and footnote disclosure requirements.

FSP APB 14-1, “Accounting for Convertible Debt Instruments that may be Settled in Cash upon Conversion (Including Partial Cash Settlement)” (FSP APB 14-1)

FSP APB 14-1 is effective for financial statement reporting periods beginning January 1, 2009 for DPL and shall be applied retrospectively to all periods presented. DPL does not currently have any convertible debt instruments outstanding; however, these types of instruments may be considered for financing future endeavors.

EITF Issue No. 07-05, “Determining Whether an Instrument (or Embedded Feature) is Indexed to an Entity’s Own Stock” (EITF 07-05)

EITF 07-05 applies to financial statement periods beginning January 1, 2009 for DPL to any outstanding instruments. The cumulative effect of the change in accounting principle shall be recognized as an adjustment to the opening balance of retained earnings for that fiscal year in which this issue is initially applied, presented separately. DPL does not currently have any financial instruments that are indexed to its own stock outstanding; however, these types of instruments may be considered for financing future endeavors.

DPL

FSP FAS 133-1 and FIN 45-4, “Disclosure About Credit Derivatives and Certain Guarantees” (FSP FAS 133-1 and FIN 45-4)

For credit derivatives, FSP FAS 133-1 requires disclosure on the nature and fair value of the credit derivative, the approximate term, the reasons for entering the derivative, the events requiring performance, and the current status of the payment/performance risk. It also requires disclosure of the maximum potential amount of future payments without any reduction for possible recoveries under collateral provisions, recourse provisions, or liquidation proceeds. For guarantees, FSP FAS 133-1 requires disclosure on the current status of the payment/performance risk and whether the current status is based on external credit ratings or current internal groupings used to manage risk. If internal groupings are used, then information is required about how the groupings are determined and used for managing risk.

The new disclosures are required starting with financial statement reporting periods ending December 31, 2008 for DPL. Comparative disclosures are only required for periods ending after initial adoption. DPL is currently evaluating the impact on its disclosures.

(5) SEGMENT INFORMATION

DPL has identified its regulated utility business as its only reporting and operating segment based on the provisions of SFAS 131, “Disclosures about Segments of an Enterprise and Related Information”.

(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 September 30, 2008, of $16.1 million includes $.8 million for DPL’s allocated share. PHI's pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2008, of $48.3 million includes $2.5 million for DPL's allocated share.

PHI’s pension and other postretirement net periodic benefit cost for the three months ended September 30, 2007, of $20.5 million includes $.6 million for DPL’s allocated share. PHI's pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2007, of $48.4 million includes $1.8 million for DPL's allocated share.

(7) DEBT

PHI, Potomac Electric Power Company (Pepco), DPL and Atlantic City Electric Company (ACE) maintain a credit facility to provide for their respective short-term liquidity

DPL

As a result of severe liquidity constraints in the credit, commercial paper and capital markets during October 2008, DPL borrowed under the $1.5 billion credit facility. Typically, DPL issues commercial paper if required to meet its short-term working capital requirements. Given the lack of liquidity in the commercial paper markets, DPL borrowed under the credit facility to maintain sufficient cash on hand to meet daily short-term operating needs. At September 30, 2008, DPL did not borrow under the facility. In October, DPL borrowed $150 million.

In July 2008, DPL amended its $150 million loan agreement to convert it into a 364-day facility that matures in July 2009.

(8) INCOME TAXES

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

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2008		2007		2008		2007

Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect	5.4		5.0		5.4		5.0
Depreciation	(1.2)		2.7		1.0		3.0
Tax credits	(1.2)		(.9)		(.8)		(1.0)
Adjustment to prior years’ tax	(5.3)		.9		(1.1)		-
Change in estimates and interest related to uncertain and effectively settled tax positions	-		1.4		(7.0)		(3.9)
Deferred tax adjustment	-		5.5		-		2.0
Other, net	-		(.3)		.1		-

Effective Income Tax Rate	32.7	%	49.3	%	32.6	%	40.1	%

DPL’s effective tax rates for the three months ended September 30, 2008 and 2007 were 32.7% and 49.3%, respectively. The decrease in the effective tax rate resulted from a decrease in the adjustment to prior year taxes due to the finalization of the tax return, a decrease in the benefit recognized on changes in estimates and interest related to uncertain and effectively settled tax positions, and a deferred tax adjustment recorded in 2007.

DPL

DPL’s effective tax rates for the nine months ended September 30, 2008 and 2007 were 32.6% and 40.1%, respectively. The decrease in the effective tax rate resulted from decreases in certain depreciation book/tax differences, adjustments to prior year taxes due to the finalization of the tax return, the benefit recognized on changes in estimates and interest related to uncertain and effectively settled tax positions, and a deferred tax adjustment recorded in 2007.

During the second quarter 2008, DPL reached a tentative settlement with the Internal Revenue Service (IRS) concerning the treatment of mixed service costs for income tax purposes during the period 2001 to 2004. See “Commitments and Contingencies — Regulatory and Other Matters — IRS Mixed Service Cost Issue” in Note (10). On the basis of the tentative settlement, DPL updated its estimated liability related to mixed service costs and as a result, recorded a net reduction in its liability for unrecognized tax benefits of $.8 million and recognized after-tax interest income of $2.3 million in the second quarter of 2008.

(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 3 – Pricing inputs include significant inputs that are generally less observable than those from objective sources. Level 3 includes those financial investments that are valued using

DPL

models or other valuation methodologies. DPL’s Level 3 instruments are custom priced natural gas options. Some non-standard assumptions are used in their forward valuation to adjust for the customized pricing; otherwise, most of the options follow NYMEX valuation. A few of the options have no significant NYMEX components, and have to be priced using internal volatility assumptions. Some of the options do not expire until December 2011. All of the options are part of the natural gas hedging program approved by the Delaware Public Service Commission.

The following table sets forth by level within the fair value hierarchy DPL's financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 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	September 30, 2008		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)

ASSETS
Cash equivalents	$	12.0	$	12.0	$	-	$	-
Executive deferred compensation plan assets		3.9		3.1		-		.8
	$	15.9	$	15.1	$	-	$	.8

LIABILITIES
Derivative instruments	$	27.7	$	18.2	$	(.1)	$	9.6
Executive deferred compensation plan liabilities		.6		-		.6		-
	$	28.3	$	18.2	$	.5	$	9.6

DPL

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		1.6		-
Included in other comprehensive income		-		-
Purchases and issuances		-		-
Settlements		(.5)		-
Transfers in and/or out of Level 3		-		-
Ending balance as of September 30, 2008	$	(9.6)	$	.8


Gains (realized and unrealized) included in earnings 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 for the period above	$	1.6	$	-

Change in unrealized gains relating to assets still held at reporting date	$	(.5)	$	-

(10) COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Rate Proceedings

In electric service distribution base rate cases filed by DPL in Maryland, and in a natural gas distribution case filed by DPL in Delaware, 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 increases rates if actual distribution revenues fall below the level approved by the applicable commission and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, the utility collects its authorized revenues for distribution deliveries. As a consequence, a BSA “decouples” revenue from unit sales 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 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.

DPL

Delaware

In August 2006, DPL submitted an application to the Delaware Public Service Commission (DPSC) for an increase in its natural gas distribution base rates, including a proposed BSA. In March 2007, the DPSC approved a settlement agreement filed by all of the parties in that proceeding (DPL, the DPSC Staff and the Delaware Division of Public Advocate), which included a rate increase. Although the settlement agreement did not include a BSA, it provided for all of the parties to the case to participate in a statewide proceeding for the purpose of investigating a BSA or other decoupling mechanisms for all electric and gas distribution utilities in Delaware. In March 2007, the DPSC issued an order initiating a docket for the purpose of investigating whether decoupling mechanisms should be adopted for Delaware’s regulated utilities. On September 16, 2008, the DPSC issued an order that sets forth a method of revenue decoupling for DPL developed by the DPSC staff, referred to as a modified fixed variable rate design (MFVRD). This design relies primarily upon a fixed customer charge (i.e., not tied to the customer’s volumetric consumption) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, DPL believes that the MFRVD can serve as an appropriate revenue decoupling mechanism. The specific rate design of a proposed MFRVD will be established in the context of DPL’s next base rate case (presumably electric); however, the DPSC retained the flexibility to address these rate design changes outside of a base rate case if the situation is warranted. This would permit the DPSC to apply a MFVRD to DPL’s natural gas rates without the necessity of a full base rate case.

Maryland

In July 2007, the Maryland Public Service Commission (MPSC) issued an order in DPL’s electric service distribution rate case, 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 July 19, 2008, pending a Phase II proceeding in which the MPSC considered the results of an audit of DPL’s cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates was required. On July 18, 2008, the MPSC issued an order covering the Phase II proceedings, denying any further adjustment to DPL’s rates, thus making permanent the rate increases approved in the July 2007 order. The MPSC also issued an order on August 4, 2008, further explaining its July 18 order.

DPL

On August 18, 2008, DPL filed a general notice of appeal of both the July 18 and August 4 orders (under Maryland rules, a petitioner is not required to specify the basis of the appeal in the notice of appeal). The appeal was filed in the Circuit Court for Cecil County, Maryland. The MPSC filed a motion to transfer the proceedings from the Circuit Court of Cecil County to the Circuit Court for Baltimore City. A motions hearing has been scheduled for December 1, 2008 in Cecil County. No action has been taken in Montgomery County. DPL’s memorandum on appeal, which will specify the basis of DPL’s appeal, is due in the Cecil County Circuit on November 17, 2008.

Federal Energy Regulatory Commission

On August 18, 2008, DPL submitted an application with the Federal Energy Regulatory Commission (FERC) for incentive rate treatments in connection with PHI’s 230-mile, 500-kilovolt Mid-Atlantic Power Pathway Project (the MAPP Project). The application requested that FERC include all of DPL’s Construction Work in Progress in rate base, an ROE adder of 150 basis points and the recovery of prudently incurred costs in the event the project is abandoned or terminated for reasons beyond DPL’s control. On October 31, 2008, FERC granted unanimous approval of the requested rate incentives.

Sale of Virginia Operations

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.

DPL

Carolina Transformer Site. In August 2006, the U.S. Environmental Protection Agency (EPA) notified DPL that it had 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 may be a potentially responsible party (PRP). In early 2008, EPA, the PRP group and the State of North Carolina entered into a settlement agreement under which (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 covenanted not to sue or bring administrative action against DPL for response costs at the site, (iii) other PRP group members released all rights for cost recovery or contribution claims they may have against DPL, and (iv) DPL released all rights for cost recovery or contribution claims that it may have against other parties settling with EPA and the State of North Carolina. On September 24, 2008, the U.S. District Court for the Eastern District of North Carolina entered a consent decree which resolves DPL’s liability at the site.

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 believed would be acceptable to the IRS.

At the same time as the proposed regulations were released, the IRS issued Revenue Ruling 2005-53, which was 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 included in the audit matters relating to the 2001 and 2002 audits pending before the U.S. Office of Appeals of the IRS (Appeals Office).

In February 2006, PHI paid approximately $121 million of taxes (a portion of which is attributable to DPL) 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. In June 2008, PHI received from the Appeals Office an offer of settlement pertaining to DPL for the tax years 2001 through 2004. DPL is substantially in agreement with this proposed settlement. Based on the terms of the proposal, DPL expects the final settlement amount to be less than the amount previously deposited.

DPL

There was no further correspondence on this issue between the Appeals Office and DPL during the quarter ended September 30, 2008. On the basis of the tentative settlement, DPL updated its estimated liability related to mixed service costs and as a result, recorded a net reduction in its liability for unrecognized tax benefits of $.8 million and recognized after-tax interest income of $2.3 million. All of the adjustments related to the tentative settlement were recorded in the quarter ended June 30, 2008, and no additional interest or adjustments to the unrecognized tax benefits were recorded during the quarter ended September 30, 2008.

(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. PHI Service Company costs directly charged or allocated to DPL for the three months ended September 30, 2008 and 2007 were $28.9 million and $27.2 million, respectively. PHI Service Company costs directly charged or allocated to DPL for the nine months ended September 30, 2008 and 2007 were approximately $83.8 million and $79.9 million, respectively.

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

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2008		2007		2008		2007
	(Millions of dollars)
Income (Expense)
SOS with Conectiv Energy Supply (a)	$	(42.5)	$	(73.8)	$	(146.6)	$	(209.3)	(
Intercompany lease transactions (b)		1.9		1.8		5.4		5.6
Transcompany pipeline gas purchases with Conectiv Energy Supply (c)		(1.1)		-		(2.3)		(1.5)
Transcompany pipeline gas sales with Conectiv Energy Supply (d)		.2		.5		.6		2.2

(a)	Included in fuel and purchased energy.

(b)	Included in electric revenue.

(c)	Included in gas purchased.

(d)	Included in gas revenue.

As of September 30, 2008 and December 31, 2007, DPL had the following balances on its Balance Sheets due (to)/from related parties:

	September 30, 2008		December 31, 2007
Asset (Liability)		(Millions of dollars)
Payable to Related Party (current)
PHI Service Company	$	(20.5)	$	(24.7)
Conectiv Energy Supply		(11.1)		(23.0)
Pepco Energy Services		(7.4)		(6.6)

The items listed above are included in the “Accounts payable to associated companies” balance on the Balance Sheet of $39.0 million and $54.0 million at September 30, 2008 and December 31, 2007, respectively.

Money Pool Balance with Pepco Holdings (included in short-term debt)	$	(85.1)	$	(157.4)

Money Pool Interest Accrued (included in interest accrued)	$	(.2)	$	(.6)

THIS PAGE INTENTIONALLY LEFT BLANK.

ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
		2008		2007		2008		2007
		(Millions of dollars)

Operating Revenue	$	540.5	$	504.7	$	1,289.2	$	1,181.2

Operating Expenses
Fuel and purchased energy		394.6		349.1		913.3		815.9
Other operation and maintenance		50.0		41.7		139.0		118.6
Depreciation and amortization		30.6		21.0		79.8		55.5
Other taxes		6.9		7.8		18.4		17.5
Deferred electric service costs		12.0		29.1		20.0		45.1
Gain on sale of assets		-		-		-		(.4)
Total Operating Expenses		494.1		448.7		1,170.5		1,052.2

Operating Income		46.4		56.0		118.7		129.0

Other Income (Expenses)
Interest and dividend income		.1		.3		.7		1.1
Interest expense		(14.6)		(16.2)		(44.1)		(48.4)
Other income		.7		1.4		2.4		3.8
Other expense		-		-		(.7)		-
Total Other Expenses		(13.8)		(14.5)		(41.7)		(43.5)

Income Before Income Tax Expense		32.6		41.5		77.0		85.5

Income Tax Expense		12.5		15.0		24.2		32.2

Income from Continuing Operations		20.1		26.5		52.8		53.3

Discontinued Operations (Note (12))
Income from operations (net of taxes of zero for the three months ended September 30, 2008 and 2007, respectively, and zero and $.1 million for the nine months ended September 30, 2008 and 2007, respectively)		-		-		-		.1

Net Income		20.1		26.5		52.8		53.4

Dividends on Redeemable Serial Preferred Stock		.1		.1		.2		.2

Earnings Available for Common Stock		20.0		26.4		52.6		53.2

Retained Earnings at Beginning of Period		143.4		128.8		141.8		132.0

Dividends Paid to Parent		-		(20.0)		(31.0)		(50.0)

Retained Earnings at End of Period	$	163.4	$	135.2	$	163.4	$	135.2

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

ACE

ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)
ASSETS		September 30, 2008		December 31, 2007
	(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$	47.1	$	7.0
Restricted cash equivalents			12.5		9.5
Accounts receivable, less allowance for uncollectible accounts of $6.6 million and $4.9 million, respectively			221.4		198.1
Fuel, materials and supplies - at average cost			13.6		14.1
Prepayments of income taxes			53.5		47.0
Prepaid expenses and other			46.3		16.8
Total Current Assets			394.4		292.5

INVESTMENTS AND OTHER ASSETS
Regulatory assets			778.5		818.0
Restricted funds held by trustee			4.4		6.8
Prepaid pension expense			6.7		8.5
Other			51.5		36.9
Total Investments and Other Assets			841.1		870.2

PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			2,183.0		2,078.0
Accumulated depreciation			(657.8)		(633.5)
Net Property, Plant and Equipment			1,525.2		1,444.5

TOTAL ASSETS		$	2,760.7	$	2,607.2

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

ACE

ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)
LIABILITIES AND SHAREHOLDER’S EQUITY		September 30, 2008		December 31, 2007
	(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt		$	219.2	$	51.7
Current maturities of long-term debt			31.9		81.0
Accounts payable and accrued liabilities			136.9		128.9
Accounts payable to associated companies			31.8		18.3
Taxes accrued			33.4		30.2
Interest accrued			10.6		13.3
Liabilities and accrued interest related to uncertain tax positions			6.4		26.6
Other			33.2		37.0
Total Current Liabilities			503.4		387.0

DEFERRED CREDITS
Regulatory liabilities			422.2		430.9
Deferred income taxes, net			411.4		386.3
Investment tax credits			10.3		11.1
Other postretirement benefit obligation			38.2		38.0
Liabilities and accrued interest related to uncertain tax positions			48.4		6.0
Other			14.6		15.2
Total Deferred Credits			945.1		887.5

LONG-TERM LIABILITIES
Long-term debt			361.1		415.7
Transition Bonds issued by ACE Funding			411.0		433.5
Total Long-Term Liabilities			772.1		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, 8,546,017 shares outstanding			25.6		25.6
Premium on stock and other capital contributions			344.9		309.9
Retained earnings			163.4		141.8
Total Shareholder’s Equity			533.9		477.3

TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY		$	2,760.7	$	2,607.2

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

100

ACE

ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

		Nine Months Ended September 30,
			2008		2007
	(Millions of dollars)
OPERATING ACTIVITIES
Net income		$	52.8	$	53.4
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization			79.8		55.5
Deferred income taxes			18.5		23.3
Gain on sale of assets			-		(.4)
Changes in:
Accounts receivable			(23.3)		(63.5)
Accounts payable and accrued liabilities			24.9		12.0
Prepaid New Jersey sales and excise tax			(48.0)		(46.3)
Regulatory assets and liabilities			(1.9)		34.5
Interest and taxes accrued			16.6		(.5)
Proceeds from sale of B.L. England emission allowances			-		25.3
Other changes in working capital			.4		.1
Net other operating			5.0		(4.8)
Net Cash From Operating Activities			124.8		88.6

INVESTING ACTIVITIES
Net investment in property, plant and equipment			(121.8)		(91.0)
Proceeds from sale of assets			1.0		9.0
Net other investing activities			(.5)		7.1
Net Cash Used By Investing Activities			(121.3)		(74.9)

FINANCING ACTIVITIES
Dividends paid to Parent			(31.0)		(50.0)
Dividends paid on preferred stock			(.2)		(.2)
Capital contribution from Parent			35.0		-
Reacquisition of long-term debt			(126.3)		(36.9)
Issuances of short-term debt, net			167.8		73.4
Net other financing activities			(8.7)		(.5)
Net Cash From (Used By) Financing Activities			36.6		(14.2)

Net Increase (Decrease) in Cash and Cash Equivalents			40.1		(.5)
Cash and Cash Equivalents at Beginning of Period			7.0		5.5

CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	47.1	$	5.0

NON-CASH ACTIVITIES
Capital contribution in respect of certain intercompany transactions		$	-	$	3.0

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for income taxes (includes payments to PHI for Federal income taxes)		$	10.6	$	33.0

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ATLANTIC CITY ELECTRIC COMPANY

(1) ORGANIZATION

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

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.

Impact of the Current Capital and Credit Market Disruptions

The recent disruptions in the capital and credit markets have had an impact on ACE’s business. While these conditions have required ACE to make certain adjustments in its financial management activities, ACE believes that it currently has sufficient liquidity to fund its operations and meet its financial obligations. These market conditions, should they continue, however, could have a negative effect on ACE’s financial condition, results of operations and cash flows.

Liquidity Requirements

ACE depends on access to the capital and credit markets to meet its liquidity and capital requirements. To meet its liquidity requirements, ACE historically has relied on the issuance of commercial paper and short-term notes and on bank lines of credit to supplement internally generated cash from operations. ACE’s primary credit source is PHI’s $1.5 billion syndicated credit facility, under which ACE can borrow funds, obtain letters of credit and support the issuance of commercial paper in an amount up to $500 million (subject to the limitation that the total utilization by Pepco, DPL and ACE cannot exceed $625 million). This facility is in effect until May 2012 and consists of commitments from 17 lenders, no one of which is responsible for more than 8.5% of the total commitment.

Due to the capital and credit market disruptions, the market for commercial paper in September and October 2008 has been severely restricted for most companies. As a result, ACE has not been able to issue commercial paper on a day-to-day basis either in amounts or with maturities that it typically has required for cash management purposes. Given its restricted access to the commercial paper market and the uncertainty in the credit markets generally, ACE borrowed $135 million under the credit facility to create a cash reserve for future short-term operating needs. After giving effect to outstanding letters of credit and commercial paper, PHI’s utility subsidiaries have an aggregate of $308 million in combined cash and borrowing capacity under the credit facility as of September 30, 2008. During the month of October 2008,

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the average daily amount of the combined cash and borrowing capacity of PHI’s utility subsidiaries was $286 million and ranged from a low of $178 million to a high of $350 million.

To address the challenges posed by the current capital and credit market environment and to ensure that it will continue to have sufficient access to cash to meet its liquidity needs, ACE has identified a number of cash and liquidity conservation measures, including opportunities to defer capital expenditures due to lower than anticipated growth. Several measures to reduce expenditures have been taken. Additional measures could be undertaken if conditions warrant.

Due to the financial market conditions, which have caused uncertainty of short-term funding, ACE obtained approval from the New Jersey Board of Public Utilities to issue up to $250 million in long-term debt securities no later than December 31, 2008. The proceeds can be used to refund short-term debt incurred to finance utility construction and operations on a temporary basis and incurred to fund the temporary repurchase of tax-exempt auction rate securities.

Pension and Postretirement Benefit Plans

ACE participates in pension and postretirement benefit plans sponsored by PHI for employees. While the plans have not experienced any significant impact in terms of liquidity or counterparty exposure due to the disruption of the capital and credit markets, the recent stock market declines have caused a decrease in the market value of benefit plan assets over the nine months ended September 30, 2008.

(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 September 30, 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 and nine months ended September 30, 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

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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 third 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 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 purchases with the counterparties to the NUGs for the three months ended September 30, 2008 and 2007 were approximately $93 million and $88 million, respectively, of which approximately $82 million and $79 million, respectively, were related to power purchases under the NUGs. Net power purchase activities with the counterparties to the NUGs for the nine months ended September 30, 2008 and 2007 were approximately $265 million and $248 million, respectively, of which approximately $233 million and $222 million, respectively, were 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 $7.1 million for the three months ended September 30, 2008 and 2007, and $17.3 million and $17.6 million for the nine months ended September 30, 2008 and 2007, respectively.

Reclassifications and Adjustments

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

In the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the Long-Term Incentive Plan which resulted in an understatement of ACE’s stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in ACE’s Other Operation and Maintenance expenses for the three and nine months ended September 30, 2008 of $1.3 million. This adjustment is not considered material.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 157, "Fair Value Measurements" (SFAS No. 157)

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liability in an orderly transaction between market participants in the most advantageous market using the best available information. The provisions of SFAS No. 157 were effective for financial statements beginning January 1, 2008 for ACE.

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 required 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.” ACE is currently evaluating the impact of SFAS No. 157-2 on non-financial assets (including liabilities); however, ACE does not anticipate that the application of SFAS No. 157 to its other non-financial assets and non-financial liabilities would materially affect its overall financial condition, results of operations or cash flows.

On September 30, 2008, the Securities and Exchange Commission and FASB issued guidance on fair value measurements, which was amplified on October 10, 2008 by the FASB in FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active.” This guidance clarifies the application of SFAS No. 157 to assets in an inactive market and illustrates how to determine the fair value of a financial asset in an inactive market. The guidance was effective beginning with the September 30, 2008 reporting period for ACE and has not had a material impact on ACE’s results.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities–including an Amendment of FASB Statement No. 115” (SFAS No. 159)

On February 15, 2007, the FASB issued SFAS No. 159, which permits entities to elect to measure eligible financial instruments at fair value. SFAS No. 159 applies to other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. On January 1, 2008, ACE did not elect the fair value option for its eligible financial assets and liabilities.

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(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

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

On December 4, 2007, the FASB issued 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 be used for all business combinations and for an acquirer to be identified for each business combination. However, SFAS 141 (R) expands the definition of a business and amends FASB Statement No. 109, “Accounting for Income Taxes” to require the acquirer to recognize changes in the amount of its deferred tax benefits that are realizable because of a business combination either in income from continuing operations or directly in contributed capital, depending on the circumstances.

SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009 for ACE. ACE is currently evaluating the potential impact SFAS No. 141(R) may have on its overall financial condition, results of operations, cash flows and footnote disclosure requirements.

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

SFAS No. 160 is effective prospectively for financial statement reporting periods beginning January 1, 2009 for ACE, 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 and footnote disclosure requirements.

SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162)

On May 9, 2008, the FASB issued SFAS No. 162, which identifies the sources of accounting principles and the hierarchy for selecting the principles to be used in the preparation

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of financial statements of nongovernmental entities that are presented in conformity with GAAP in the United States. Moving the GAAP hierarchy into the accounting literature directs the responsibility for applying the hierarchy to the reporting entity, rather than just to the auditors.

SFAS No. 162 will be effective for ACE as of November 15, 2008. The FASB believes that the application of SFAS No. 162 is not expected to result in a change in accounting; however, if it does, the accounting change must be reported as a change in accounting principle under SFAS No. 154, “Accounting Changes and Error Corrections.” ACE is currently evaluating the impact SFAS No. 162 may have on its overall financial condition, results of operations, cash flows and footnote disclosure requirements.

FSP APB 14-1, “Accounting for Convertible Debt Instruments that may be Settled in Cash upon Conversion (Including Partial Cash Settlement)” (FSP APB 14-1)

FSP APB 14-1 is effective for financial statement reporting periods beginning January 1, 2009 for ACE and shall be applied retrospectively to all periods presented. ACE does not currently have any convertible debt instruments outstanding; however, these types of instruments may be considered for financing future endeavors.

EITF Issue No. 07-05, “Determining Whether an Instrument (or Embedded Feature) is Indexed to an Entity’s Own Stock” (EITF 07-05)

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EITF 07-05 applies to financial statement periods beginning January 1, 2009 for ACE to any outstanding instruments. The cumulative effect of the change in accounting principle shall be recognized as an adjustment to the opening balance of retained earnings for that fiscal year in which this issue is initially applied, presented separately. ACE does not currently have any financial instruments that are indexed to its own stock outstanding; however, these types of instruments may be considered for financing future endeavors.

FSP FAS 133-1 and FIN 45-4, “Disclosure About Credit Derivatives and Certain Guarantees” (FSP FAS 133-1 and FIN 45-4)

For credit derivatives, FSP FAS 133-1 requires disclosure on the nature and fair value of the credit derivative, the approximate term, the reasons for entering the derivative, the events requiring performance, and the current status of the payment/performance risk. It also requires disclosure of the maximum potential amount of future payments without any reduction for possible recoveries under collateral provisions, recourse provisions, or liquidation proceeds. For guarantees, FSP FAS 133-1 requires disclosure on the current status of the payment/performance risk and whether the current status is based on external credit ratings or current internal groupings used to manage risk. If internal groupings are used, then information is required about how the groupings are determined and used for managing risk.

The new disclosures are required starting with financial statement reporting periods ending December 31, 2008 for ACE. Comparative disclosures are only required for periods ending after initial adoption. ACE is currently evaluating the impact on its disclosures.

(5) SEGMENT INFORMATION

ACE has identified its regulated utility business as its only reporting and operating segment based on the provisions of SFAS 131, “Disclosures about Segments of an Enterprise and Related Information”.

(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 September 30, 2008, of $16.1 million includes $2.9 million for ACE’s allocated share. PHI's pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2008, of $48.3 million includes $8.8 million for ACE's allocated share.

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PHI’s pension and other postretirement net periodic benefit cost for the three months ended September 30, 2007, of $20.5 million includes $2.9 million for ACE’s allocated share. PHI's pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2007, of $48.4 million includes $8.7 million for ACE's allocated share.

(7) DEBT

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

As a result of severe liquidity constraints in the credit, commercial paper and capital markets during September 2008, ACE borrowed under the $1.5 billion credit facility. Typically, ACE issues commercial paper if required to meet its short-term working capital requirements. Given the lack of liquidity in the commercial paper markets, ACE borrowed under the credit facility to maintain sufficient cash on hand to meet daily short-term operating needs. At September 30, 2008, ACE borrowed $135 million. The LIBOR-based loan matured during October 2008 and was rolled to November 2008.

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(8) INCOME TAXES

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

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2008		2007		2008		2007

Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect	7.4		6.7		7.1		6.7
Tax credits	(.9)		(.7)		(1.0)		(1.2)
Adjustment to prior years’ tax	(3.1)		(3.1)		(1.3)		(1.8)
Change in estimates and interest related to uncertain and effectively settled tax positions	.3		(.2)		(7.4)		(.6)
Deferred tax adjustment	-		(1.4)		-		(.7)
Other, net	(.4)		(.2)		(1.0)		.3

Consolidated Effective Income Tax Rate	38.3	%	36.1	%	31.4	%	37.7	%

ACE’s effective tax rates for the three months ended September 30, 2008 and 2007 were 38.3% and 36.1%, respectively. The increase in the effective tax rate resulted from a change in estimates and interest related to uncertain and effectively settled tax positions, and a deferred tax adjustment recorded in 2007.

ACE’s effective tax rates for the nine months ended September 30, 2008 and 2007 were 31.4% and 37.7%, respectively. The decrease in the effective tax rate resulted from a change in estimates and interest related to uncertain and effectively settled tax positions (primarily related to a claim made for repair costs on prior year returns and reduction in previously accrued interest in the second quarter of 2008 related to the uncertain tax positions for the tentative IRS settlement on the mixed service cost issue), and an adjustment to prior years’ taxes due to the finalization of tax returns, partially offset by a deferred tax adjustment recorded in 2007.

During the second quarter 2008, ACE reached a tentative settlement with the IRS concerning the treatment of mixed service costs for income tax purposes during the period 2001 to 2004. See “Commitments and Contingencies — Regulatory and Other Matters — IRS Mixed Service Cost Issue” in Note (10). On the basis of the tentative settlement, ACE updated its estimated liability related to mixed service costs and as a result, recorded a net reduction in its liability for unrecognized tax benefits of $2.1 million and recognized after-tax interest income of $2.2 million in the second quarter of 2008.

(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.

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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 3 – Pricing inputs include significant inputs that are generally less observable than those from objective sources. Level 3 includes those financial investments that are valued using models or other valuation methodologies. 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.

The following table sets forth by level within the fair value hierarchy ACE's financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 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.

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	Fair Value Measurements at Reporting Date Using
	(Millions of dollars)
Description	September 30, 2008		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)

ASSETS
Cash equivalents	$	57.7	$	57.7	$	-	$	-
Executive deferred compensation plan assets		1.0		.7		-		.3
	$	58.7	$	58.4	$	-	$	.3

LIABILITIES
Executive deferred compensation plan liabilities	$	.8	$	-	$	.8	$	-
	$	.8	$	-	$	.8	$	-

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		-
Included in other comprehensive income		-
Purchases and issuances		-
Settlements		-
Transfers in and/or out of Level 3		-
Ending balance as of September 30, 2008	$	.3


Gains or (losses) (realized and unrealized) included in earnings for the period above are reported in Other Operation and Maintenance Expense as follows:		Other Operation and Maintenance Expense

Total gains included in earnings for the period above	$	-

Change in unrealized gains relating to assets still held at reporting date	$	-

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(10) COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Rate Proceedings

Federal Energy Regulatory Commission

On August 18, 2008, ACE submitted an application with the Federal Energy Regulatory Commission (FERC) for incentive rate treatments in connection with PHI’s 230-mile, 500-kilovolt Mid-Atlantic Power Pathway Project (the MAPP Project). The application requested that FERC include ACE’s Construction Work in Progress in rate base, an ROE adder of 150 basis points and the recovery of prudently incurred costs in the event the project is abandoned or terminated for reasons beyond ACE’s control. On October 31, 2008, FERC granted unanimous approval of the requested rate incentives.

Sale of B.L. England Generating Facility

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.

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

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 believed would be acceptable to the IRS.

At the same time as the proposed regulations were released, the IRS issued Revenue Ruling 2005-53, which was 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

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protest of the IRS adjustments is included in the audit matters relating to the 2001 and 2002 audits pending before the U.S. Office of Appeals of the IRS (Appeals Office).

In February 2006, PHI paid approximately $121 million of taxes (a portion of which is attributable to ACE) 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. In June 2008, PHI received from the Appeals Office an offer of settlement pertaining to ACE for the tax years 2001 through 2004. ACE is substantially in agreement with this proposed settlement. Based on the terms of the proposal, ACE expects the final settlement amount to be less than the amount previously deposited.

There was no further correspondence on this issue between the Appeals Office and ACE during the quarter ended September 30, 2008. On the basis of the tentative settlement, ACE updated its estimated liability related to mixed service costs and as a result, recorded a net reduction in its liability for unrecognized tax benefits of $2.1 million and recognized after-tax interest income of $2.2 million. All of the adjustments related to the tentative settlement were recorded in the quarter ended June 30, 2008 and, no additional interest or adjustments to the unrecognized tax benefits were recorded during the quarter ended September 30, 2008.

(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. PHI Service Company costs directly charged or allocated to ACE for the three and nine months ended September 30, 2008 and 2007 were $23.1 million and $20.6 million and $66.6 million and $60.0 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:

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2008		2007		2008		2007
	(Millions of dollars)
Income (Expense)
Purchased power from Conectiv Energy Supply (a)	$	(70.7)	$	(36.1)	$	(128.4)	$	(77.1)	(
Meter reading services provided by Millennium Account Services LLC (b)	$	(1.0)	$	(1.0)	$	(2.9)	$	(2.9)
Intercompany lease transactions (b)		(.4)		(.3)		(1.1)		(1.0)
Intercompany use revenue (c)		.5		.4		1.5		1.4
Intercompany use expense (c)		(.5)		(.4)		(1.5)		(1.4)

(a) Included in fuel and purchased energy.

(b) Included in other operation and maintenance.

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As of September 30, 2008 and December 31, 2007, ACE had the following balances on its Consolidated Balance Sheets due (to)/from related parties:

		September 30, 2008	December 31, 2007
Asset (Liability)		(Millions of dollars)
Payable to Related Party (current)
PHI Service Company	$	(11.2)	$	(10.4)
Conectiv Energy Supply		(19.4)		(7.8)

The items listed above are included in the “Accounts payable to associated companies” balance on the Consolidated Balance Sheet of $31.8 million and $18.3 million at September 30, 2008 and December 31, 2007, respectively.

(12) DISCONTINUED OPERATIONS

As discussed in Note (10) “Commitments and Contingencies,” herein, in February 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 and nine months ended September 30, 2007.

The following table summarizes discontinued operations information for the three and nine months ended September 30, 2007:

	For the Three Months Ended September 30, 2007		For the Nine Months Ended September 30, 2007
	(Millions of dollars)

Operating Revenue	$	-	$	9.7

Income Before Income Tax Expense	$	-	$	.2

Net Income	$	-	$	.1

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117

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	119
Pepco	169
DPL	179
ACE	190

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PEPCO HOLDINGS

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

PEPCO HOLDINGS, INC.

GENERAL OVERVIEW

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 September 30, 2008 and 2007, respectively, PHI’s Power Delivery operations produced 55% and 58% of PHI’s consolidated operating revenues (including revenues from intercompany transactions) and 63% and 68% of PHI’s consolidated operating income (including income from intercompany transactions). For the nine months ended September 30, 2008 and 2007, respectively, PHI’s Power Delivery operations produced 52% and 57% of PHI’s consolidated operating revenues (including revenues from intercompany transactions) and 70% and 68% of PHI’s consolidated operating income (including income from intercompany transactions).

For the three months ended September 30, 2008 and 2007, the distribution, transmission and default supply of electric power accounted for 97% of Power Delivery’s operating revenues and the delivery and supply of natural gas contributed 3% of Power Delivery’s operating revenues. For the nine months ended September 30, 2008 and 2007, respectively, the distribution, transmission and default supply of electric power accounted for 94% and 95% of Power Delivery’s operating revenues and the delivery and supply of natural gas contributed 6% and 5% of Power Delivery’s operating revenues. Power Delivery represents one operating segment for financial reporting purposes.

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

	Delaware	Standard Offer Service (SOS)

	District of Columbia	SOS

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	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.

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 Orders), 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 September 30, 2008 and 2007, the operating revenues of the Competitive Energy business (including revenue from intercompany transactions) were equal to 49%, 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 33% and 26% of PHI’s consolidated operating income for the three months ended September 30, 2008 and 2007, respectively. For the nine months ended September 30, 2008 and 2007, the operating revenues of the Competitive Energy business (including intercompany amounts) were equal to 53% and 47%, respectively, of PHI’s

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consolidated operating revenues, and the operating income of the Competitive Energy business (including operating income from intercompany transactions) was 42% and 24%, respectively, of PHI’s consolidated operating income for the nine months ended September 30, 2008 and 2007, respectively. For the three months ended September 30, 2008 and 2007, amounts equal to 8% and 10% 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. For the nine months ended September 30, 2008 and 2007, amounts equal to 7% and 10% respectively, of the operating revenues of the Competitive Energy business were attributed 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 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’s primary fuel source for its generation plants is natural gas. Conectiv Energy manages its natural gas supply using a portfolio of long-term, firm storage and transportation contracts, and a variety of derivative instruments. 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 its power plants, and the cost of purchased energy necessary to meet its power and gas supply obligations.

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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 lease investments with a book value at September 30, 2008 of approximately $1.3 billion. This activity constitutes a fourth operating segment, which is designated as “Other Non-Regulated,” for financial reporting purposes. For a discussion of PHI’s cross-border energy lease investments, see “Regulatory and Other Matters — PHI’s Cross-Border Energy Lease Investments” 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.

IMPACT OF THE CURRENT CAPITAL AND CREDIT MARKET DISRUPTIONS

Liquidity Requirements

At September 30, 2008, the amount of cash, plus the amount of credit under the credit facility, available to meet the liquidity needs of PHI on a consolidated basis totaled $787 million,

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of which $308 million consisted of the combined cash and borrowing capacity of PHI’s utility subsidiaries. During the month of October 2008, the average daily amount of the combined cash and borrowing capacity of PHI on a consolidated basis was $601 million, and for its utility subsidiaries was $286 million. This decrease in liquidity of PHI on a consolidated basis was primarily due to a significant decline in energy prices in October, which caused an increase in the collateral obligations of the Competitive Energy businesses. PHI’s liquidity is further discussed below under the heading “Capital Resources and Liquidity — Credit Facility.”

·	PHI is actively exploring a broad range of financing alternatives, including equity and debt offerings, bank loan facilities and letter of credit facilities.

·	Pepco and DPL have filed similar applications with their respective public service commissions, which are currently pending.

Under the current capital and credit market conditions, PHI anticipates that its funding costs will be higher than PHI’s cost of capital over the last several years.

Collateral Requirements of the Competitive Energy Businesses

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·	net cash collateral posted of $90.3 million on December 31, 2007,

·	net cash collateral held of $3.6 million on March 31, 2008,

·	net cash collateral held of $237.1 million on June 30, 2008, and

·	net cash collateral posted of $193.1 million on September 30, 2008.

Ongoing Monitoring of Financial and Market Conditions

PHI monitors its liquidity position on a daily basis and routinely conducts stress testing to assess the impact of changes in commodity prices on its collateral requirements. Stress testing conducted over the months of September and October, based on contractual rights and obligations in effect at the time, indicated a 1% change in forward prices corresponding to the periods under the various contractual arrangements with respect to which collateral was required would have caused an estimated change of approximately $6 million in Conectiv Energy's net collateral requirements and a change of approximately $22 million in Pepco Energy Services' net collateral requirements. PHI's net collateral obligations decrease when forward prices increase and increase when forward prices decrease.

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PHI also closely monitors its credit ratings and outlooks and those of its rated subsidiaries, and computes the hypothetical effect of changes in credit ratings on collateral requirements and the cost of capital. As more fully discussed below under the heading “Capital Resources and Liquidity — Capital Requirements — Contractual Arrangements with Credit Rating Triggers or Margining Rights,” based on contractual provisions in effect at September 30, 2008, a one-level downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries, which would decrease PHI’s rating to below “investment grade,” would increase the collateral obligation of PHI and its subsidiaries by up to $403 million.

Counterparty Credit Risk

PHI is exposed to the risk that the counterparties to contracts may fail to meet their contractual payment obligations or may fail to deliver purchased commodities or services at the contracted price. As more fully discussed in Item 7A of the 2007 Form 10-K and in Part I, Item 3 below, each entitled “Quantitative and Qualitative Disclosures About Market Risk,” PHI attempts to minimize these risks through, among other things, formal credit policies, regular assessments of counterparty creditworthiness, and the establishment of a credit limit for each counterparty.

Pension and Postretirement Benefit Plans

PHI and its subsidiaries sponsor pension and postretirement benefit plans for their employees. While the plans have not experienced any significant impact in terms of liquidity or counterparty exposure due to the disruption of the capital and credit markets, the recent stock market declines have caused a decrease in the market value of benefit plan assets over the nine months ended September 30, 2008. A negative return for the entire year will not have an impact on PHI’s results of operations for 2008; however, such a reduction in benefit plan assets is likely to result in increased pension and postretirement benefit costs in future years.

EARNINGS OVERVIEW

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

PHI’s net income for the three months ended September 30, 2008 was $118.8 million, or $.59 per share, compared to $167.6 million, or $.87 per share, for the three months ended September 30, 2007.

Net income for the three months ended September 30, 2007, included the credits set forth below in the Power Delivery operating segment, which are presented net of federal and state income taxes and are in millions of dollars:

	Mirant bankruptcy damage claims settlement		$	20.0
	Maryland income tax settlement, net of fees		$	17.7

Excluding the items listed above, net income for the three months ended September 30, 2007, would have been $129.9 million, or $.68 per share.

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PHI’s net income for the three months ended September 30, 2008 and 2007, by operating segment, is set forth in the table below (in millions of dollars):

	2008		2007		Change
Power Delivery	$	77.1	$	122.6	$	(45.5)
Conectiv Energy		48.7		36.5		12.2
Pepco Energy Services		3.0		9.8		(6.8)
Other Non-Regulated		4.7		11.2		(6.5)
Corp. & Other		(14.7)		(12.5)		(2.2)
Total PHI Net Income	$	118.8	$	167.6	$	(48.8)

Discussion of Operating Segment Net Income Variances:

Power Delivery's $45.5 million decrease in earnings is primarily due to the following:

·	$20.0 million decrease due to the Mirant bankruptcy damage claims settlement in 2007.

·	$17.7 million decrease due to the Maryland tax settlement, net of fees, in 2007.

·	$12.0 million decrease primarily due to lower sales (primarily decreased customer usage, including an unfavorable impact of weather compared to 2007).

·	$3.1 million decrease due to higher operating and maintenance costs (primarily higher employee-related costs and bad debt expense).

·	$6.0 million increase due to the impact of the distribution base rate orders ($4.1 million related to the District of Columbia, which became effective in February 2008 for Pepco, and $1.9 million related to Maryland, which became effective in June 2007 for Pepco and DPL).

Conectiv Energy's $12.2 million increase in earnings is primarily due to the following:

$8.1 million increase in Merchant Generation & Load Service primarily due to:

(i)

an increase of $13.0 million related primarily to fuel hedges; partially offset by lower default electricity supply contract sales during the summer as a result of mild weather,

(ii)

an increase of $7.7 million primarily due to higher PJM capacity prices net of capacity hedges,

(iii)

an increase of $3.5 million primarily due to the application of fair value accounting treatment with respect to excess coal hedges,

(iv)

a decrease of approximately $9.5 million in energy margins due to lower plant output as a result of milder than normal weather and lower spark spreads, and

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(v)

a decrease of $7.1 million in emissions sales margins in 2008 due to lower emission allowance sales.

$6.6 million increase in Energy Marketing primarily due to new default electricity supply contracts (in New England and New Jersey) and oil marketing margins.

$1.9 million decrease primarily due to higher plant maintenance.

Pepco Energy Services' $6.8 million decrease in earnings is primarily due the following:

$9.5 million decrease in retail energy supply business earnings including a $6.6 million loss related to congestion and power hedges accounted for at fair value and a $3.8 million decrease due to lower generation output.

$3.2 million increase in energy services business earnings primarily due to lower operating and maintenance services costs and lower fuel costs.

Other Non-Regulated’s $6.5 million decrease in earnings is primarily due to the favorable valuation of certain other PCI portfolio investments in 2007 and the on-going impact of the cross border energy lease re-evaluation in 2008; partially offset by lower interest expense.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

PHI’s net income for the nine months ended September 30, 2008 was $233.0 million, or $1.16 per share, compared to $276.4 million, or $1.43 per share, for the nine months ended September 30, 2007.

Net income for the nine months ended September 30, 2008, included the charges set forth below in the Other Non-Regulated operating segment, which are presented net of federal and state income taxes and are in millions of dollars:

	Adjustment to the equity value of cross-border energy lease investments of PCI under FSP 13-2 to reflect the impact of a change in assumptions regarding the estimated timing of the tax benefits		$	(86.0)
	Additional interest accrued under FIN 48 related to the estimated federal and state income tax obligations from the change in assumptions regarding the estimated timing of the tax benefits on cross-border energy lease investments		$	(6.9)

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Net income for the nine months ended September 30, 2007, included the credits set forth below in the Power Delivery operating segment, which are presented net of federal and state income taxes and are in millions of dollars:

	Mirant bankruptcy damage claims settlement		$	20.0
	Maryland income tax settlement, net of fees		$	17.7

Excluding the items listed above, net income would have been $325.9 million, or $1.62 per share, for the nine months ended September 30, 2008, compared with $238.7 million, or $1.24 per share for the nine months ended September 30, 2007.

PHI’s net income for the nine months ended September 30, 2008 and 2007, by operating segment, is set forth in the table below (in millions of dollars):

	2008		2007		Change
Power Delivery	$	198.9	$	202.2	$	(3.3)
Conectiv Energy		117.7		57.3		60.4
Pepco Energy Services		27.9		23.1		4.8
Other Non-Regulated		(68.8)		37.4		(106.2)
Corp. & Other		(42.7)		(43.6)		.9
Total PHI Net Income	$	233.0	$	276.4	$	(43.4)

Discussion of Operating Segment Net Income Variances:

Power Delivery's $3.3 million decrease in earnings is primarily due to the following:

·	$20.0 million decrease due to the Mirant bankruptcy damage claims settlement in 2007.

·	$17.7 million decrease due to the Maryland tax settlement, net of fees, in 2007.

·	$13.5 million decrease primarily due to lower sales (primarily unfavorable impact of weather compared to 2007).

·	$11.9 million decrease due to higher operating and maintenance costs (primarily higher preventative maintenance and system operation costs, employee-related costs and bad debt expense).

·	$33.1 million increase due to the impact of the distribution base rate orders ($22.2 million related to Maryland, which became effective in June 2007 for Pepco and DPL, and $10.9 million related to the District of Columbia, which became effective in February 2008 for Pepco).

·	$16.5 million increase due to favorable income tax adjustments primarily related to FIN 48 interest impact.

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·	$12.1 million increase due to FERC network transmission formula rate changes in June 2007 and 2008.

Conectiv Energy's $60.4 million increase in earnings is primarily due to the following:

$58.2 million increase in Merchant Generation & Load Service primarily due to:

	(i)	an increase of $22.1 million primarily due to short-term sales of firm natural gas and natural gas transportation and storage rights, the dual-fuel capability of the combined cycle mid-merit units (fuel switching), cross-commodity hedging (use of natural gas to hedge power positions), and the opportunities created by the mid-merit combined cycle units’ operating flexibility (option value) in conjunction with short-term power and fuel price volatility,
	(ii)	an increase of $19.5 million due to higher PJM capacity prices net of capacity hedges, and
	(iii)	an increase of $11.2 million due to a gain related to coal contracts accounted for at fair value.

$7.2 million increase in Energy Marketing primarily due to increased short-term power desk margins and new default electricity supply contracts.

$6.3 million decrease primarily due to higher plant maintenance.

Pepco Energy Services' $4.8 million increase in earnings is primarily due to the operations of the retail energy supply business including a $9.4 million increase in earnings as the result of more favorable congestion costs and a $4.8 million increase due to growth in the retail gas supply business; partially offset by a $7.3 million increase in Reliability Pricing Model charges, a $1.3 million loss related to congestion and power hedges accounted for at fair value, and the higher cost of electricity supply.

Other Non-Regulated’s $106.2 million decrease in earnings is primarily due to the following:

·	$86.0 million after-tax charge resulting from a $124.4 million adjustment to the equity value of the cross-border energy lease investments of PCI under FSP 13-2 to reflect the impact of a change in assumptions regarding the estimated timing of the tax benefits.

$6.9 million after-tax charge for interest accrued under FIN 48 related to estimated federal and state income tax obligations for the period from January 1, 2001 through June 30, 2008 resulting from the change in assumptions regarding the estimated timing of the tax benefits of PCI’s cross-border energy lease investments.

·	$12.5 million decrease primarily due to favorable valuation of certain other PCI portfolio investments in 2007; partially offset by lower interest expense.

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CONSOLIDATED RESULTS OF OPERATIONS

The following results of operations discussion is for the three months ended September 30, 2008, compared to the three months ended September 30, 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	$	1,667.6	$	1,596.3	$	71.3
Conectiv Energy		782.8		633.2		149.6
Pepco Energy Services		715.7		654.4		61.3
Other Non-Regulated		14.2		19.6		(5.4)
Corp. & Other		(120.8)		(133.2)		12.4
Total Operating Revenue	$	3,059.5	$	2,770.3	$	289.2

Power Delivery Business

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


		2008		2007	Change
Regulated T&D Electric Revenue	$	502.5	$	487.9	$	14.6
Default Supply Revenue		1,095.0		1,049.3		45.7
Other Electric Revenue		17.1		15.8		1.3
Total Electric Operating Revenue		1,614.6		1,553.0		61.6

Regulated Gas Revenue		18.7		19.2		(.5)
Other Gas Revenue		34.3		24.1		10.2
Total Gas Operating Revenue		53.0		43.3		9.7

Total Power Delivery Operating Revenue	$	1,667.6	$	1,596.3	$	71.3

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.

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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 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 as part of Deferred Electric Service Costs pending an adjustment of retail rates in a future proceeding. As a consequence of the order, 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.

Electric Operating Revenue


Regulated T&D Electric Revenue		2008		2007	Change
Residential	$	184.8	$	191.8	$	(7.0)
Commercial		215.1		209.7		5.4
Industrial		7.6		7.0		.6
Other		95.0		79.4		15.6
Total Regulated T&D Electric Revenue	$	502.5	$	487.9	$	14.6

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 Orders 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).

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Regulated T&D Electric Sales (Gigawatt hours (GWh))
	2008	2007	Change
Residential	5,166	5,458		(292)
Commercial	7,888	8,096		(208)
Industrial	938	977		(39)
Other	59	59		-
Total Regulated T&D Electric Sales	14,051	14,590		(539)

Regulated T&D Electric Customers (in thousands)
	2008	2007	Change
Residential	1,605	1,616		(11)
Commercial	196	197		(1)
Industrial	2	2		-
Other	2	2		-
Total Regulated T&D Electric Customers	1,805	1,817		(12)

Due to the sale of DPL’s Virginia retail electric distribution business in January 2008, the Regulated T&D Electric customer amounts listed above include a decrease of approximately 19,000 residential customers and 3,000 commercial customers.

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 $14.6 million primarily due to the following: (i) $11.2 million increase due to a distribution rate change as part of a higher New Jersey Societal Benefit Charge that became effective in June 2008 (offset in Deferred Electric Service Costs), (ii) $7.3 million increase due to a distribution rate change under the 2007 Maryland Rate Orders that became effective in June 2007, including a positive $11.2 million Revenue Decoupling Adjustment, (iii) $7.0 million increase due to District of Columbia distribution rate change that became effective in February 2008, (iv) $2.7 million increase in transmission service revenue primarily due to changes in the FERC formula rates in June 2008 partially offset by (v) $7.9 million decrease due to differences in consumption among the various customer rate classes, (vi) $3.9 million decrease due to lower weather-related sales (a 14% decrease in Heating Degree Days and a 4% decrease in Cooling Degree Days), and (vii) $3.8 million decrease due to the sale of DPL’s Virginia retail electric distribution business in January 2008.

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Default Electricity Supply

Default Supply Revenue
		2008		2007	Change
Residential	$	620.9	$	616.3	$	4.6
Commercial		359.4		328.5		30.9
Industrial		19.0		24.9		(5.9)
Other		95.7		79.6		16.1
Total Default Supply Revenue	$	1,095.0	$	1,049.3	$	45.7

Other Default Supply Revenue consists primarily of revenue from the resale of energy and capacity purchased under NUGs in the PJM RTO market.

Default Electricity Supply Sales (GWh)
	2008	2007	Change
Residential	5,006	5,314		(308)
Commercial	2,754	2,810		(56)
Industrial	155	237		(82)
Other	23	24		(1)
Total Default Electricity Supply Sales	7,938	8,385		(447)

Default Electricity Supply Customers (in thousands)
	2008	2007	Change
Residential	1,564	1,585		(21)
Commercial	166	169		(3)
Industrial	1	1		-
Other	2	2		-
Total Default Electricity Supply Customers	1,733	1,757		(24)

The change in the number of Default Electricity Supply customers was primarily due to the sale of DPL’s Virginia retail electric distribution business in January 2008, in connection with which the purchaser assumed the associated Default Supply obligations. This sale 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, increased by $45.7 million primarily due to the following: (i) $70.3 million increase in market-based Default Electricity Supply rates, (ii) $16.5 million increase in wholesale energy revenues due to the sale in PJM RTO at higher market prices of electricity purchased from NUGs, partially offset by (iii) $20.0 million decrease due to differences in consumption among the various customer rate classes, (iv) $10.7 million decrease due to lower weather-related sales (a 14% decrease in Heating Degree Days and a 4% decrease in Cooling Degree Days), and (v) $10.1 million decrease due to the sale of DPL’s Virginia retail electric distribution business.

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Gas Operating Revenue

Regulated Gas Revenue
	2008		2007		Change

Residential	$	9.1	$	9.5	$	(.4)
Commercial		6.6		6.8		(.2)
Industrial		1.3		1.5		(.2)
Transportation and Other		1.7		1.4		.3
Total Regulated Gas Revenue	$	18.7	$	19.2	$	(.5)

Regulated Gas Sales (billion cubic feet)
	2008		2007		Change

Residential		.4		.5		(.1)
Commercial		.4		.3		.1
Industrial		.1		.1		-
Transportation and Other		1.4		1.4		-
Total Regulated Gas Sales		2.3		2.3		-

Regulated Gas Customers (in thousands)
	2008		2007		Change

Residential		112		112		-
Commercial		10		9		1
Industrial		-		-		-
Transportation and Other		-		-		-
Total Regulated Gas Customers		122		121		1

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

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

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

Regulated Gas Revenue decreased by $.5 million primarily due to lower weather-related sales (a 31% decrease in Heating Degree Days).

Other Gas Revenue

Other Gas Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales, increased by $10.2 million primarily due to higher off-system sales of which (i) $13.0 million was attributable to an increase in market prices, partially offset by (ii)

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$1.9 million decrease in demand from electric generators and gas marketers that DPL was able to fulfill due to available pipeline capacity. Higher available capacity resulted from lower demand for natural gas from regulated customers caused by warmer weather in 2008 than 2007.

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. Conectiv Energy also uses a number of and various types of derivative contracts to lock in sales margins, and to economically hedge its power and fuel purchases and sales. Gains and losses on derivative contracts are netted in revenue and cost of sales as appropriate under the applicable accounting rules. For these reasons, PHI from a managerial standpoint focuses on gross margin as a measure of performance.

Conectiv Energy Gross Margin

Merchant Generation & Load Service consists primarily of electric power, capacity and ancillary services sales from Conectiv Energy's generating 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); natural gas transportation and storage; emission allowances; electric power, capacity, and ancillary services sales pursuant to competitively bid contracts entered into with affiliated and non-affiliated companies to fulfill their default electricity supply obligations; and fuel switching activities made possible by the multi-fuel capabilities of some of Conectiv Energy's power plants.

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

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Conectiv Energy Gross Margin and Operating Statistics	Three Months Ended September 30,				Change
		2008		2007
Operating Revenue ($ millions):
Merchant Generation & Load Service	$	442.0	$	312.7		$	129.3
Energy Marketing		340.8		320.5			20.3
Total Operating Revenue1	$	782.8	$	633.2		$	149.6

Cost of Sales ($ millions):
Merchant Generation & Load Service	$	328.9	$	213.5		$	115.4
Energy Marketing		324.0		314.9			9.1
Total Cost of Sales2	$	652.9	$	528.4		$	124.5

Gross Margin ($ millions):
Merchant Generation & Load Service	$	113.1	$	99.2		$	13.9
Energy Marketing		16.8		5.6			11.2
Total Gross Margin	$	129.9	$	104.8		$	25.1

Generation Fuel and Purchased Power Expenses ($ millions) 3:
Generation Fuel Expenses 4,5
Natural Gas	$	98.3	$	118.8		$	(20.5)
Coal		16.1		16.0			.1
Oil		(.5)		9.9			(10.4)
Other6		.4		.6			(.2)
Total Generation Fuel Expenses	$	114.3	$	145.3		$	(31.0)
Purchased Power Expenses 5	$	258.8	$	155.9		$	102.9

Statistics:
Generation Output (MWh):
Base-Load 7		437,049		606,378			(169,329)
Mid-Merit (Combined Cycle) 8		1,318,196		1,525,545			(207,349)
Mid-Merit (Oil Fired) 9		323		77,718			(77,395)
Peaking		30,681		80,063			(49,382)
Tolled Generation		64,957		92,630			(27,673)
Total		1,851,206		2,382,334			(531,128)

Load Service Volume (MWh) 10		2,907,205		1,868,639			1,038,566

Average Power Sales Price 11 ($/MWh):
Generation Sales 4	$	117.50	$	88.89		$	28.61
Non-Generation Sales 12	$	101.17	$	68.47		$	32.47
Total	$	107.39	$	75.84		$	31.55

Average on-peak spot power price at PJM East Hub ($/MWh) 13	$	107.66	$	88.08		$	19.58
Average around-the-clock spot power price at PJM East Hub ($/MWh) 13	$	89.62	$	68.14		$	21.48
Average spot natural gas price at market area M3 ($/MMBtu)14	$	9.71	$	6.69		$	3.02

Weather (degree days at Philadelphia Airport): 15
Heating degree days		12		19			(7)
Cooling degree days		942		1,005			(63)

1	Includes $115.3 million and $131.4 million of affiliate transactions for 2008 and 2007, respectively.

2	Includes $1.5 million and $1.3 million of affiliate transactions for 2008 and 2007, respectively. Also, excludes depreciation and amortization expense of $9.4 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.

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 Independent System Operator - New England transmission organization (ISONE).

Merchant Generation & Load Service gross margin increased approximately $14 million primarily due to:

·	An increase of approximately $13 million due to higher PJM capacity prices net of capacity hedges.

·	An increase of approximately $22 million related primarily to fuel hedges, partially offset by lower default electricity supply contract sales than projected during the summer as a result of mild weather.

·	An increase of approximately $6 million due to the application of fair value accounting treatment with respect to excess coal hedges.

·	A decrease of approximately $16 million in energy margins due to lower plant out put as a result of milder than normal weather and lower spark spreads.

·	A decrease of approximately $12 million in emissions allowance sales margins in 2008 due to lower emission allowance sales.

Energy Marketing gross margin increased approximately $11 million primarily due to:

·	An increase of approximately $6 million due to additional default electricity supply contracts in 2008.

·	An increase of approximately $4 million in oil marketing margins in 2008.

Pepco Energy Services

Pepco Energy Services’ operating revenue increased $61.3 million primarily due to (i) an increase of $45.5 million due to higher volumes of retail electric load served at higher prices in 2008 due to customer acquisitions, (ii) an increase of $8.8 million due to increased construction activities in 2008 and (iii) an increase of $7.0 due to higher natural gas volumes driven by customer acquisitions and also higher prices in 2008.

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Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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


	2008		2007		Change
Power Delivery	$	1,112.4	$	1,040.3	$	72.1
Conectiv Energy		652.9		528.4		124.5
Pepco Energy Services		686.4		615.0		71.4
Corp. & Other		(119.6)		(132.5)		12.9
Total	$	2,332.1	$	2,051.2	$	280.9

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy, which is primarily associated with Default Electric Supply sales, increased by $72.1 million primarily due to (i) $109.5 million increase in average energy costs, the result of new Default Electricity Supply contracts, (ii) $10.8 million increase due to gas purchases for off-system sales, partially offset by (iii) $26.8 million decrease due to differences in consumption among various customer rate classes, (iv) $13.2 million decrease due to the sale of DPL’s Virginia retail electric distribution business including the transfer of its Default Supply obligations in January 2008, and (v) $11.0 million decrease due to lower weather-related sales. Fuel and Purchased Energy expense is substantially offset in Default Supply Revenue, Regulated Gas Revenue, and 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 $71.4 million primarily due to (i) an increase of $62.1million due to higher volumes of purchased electricity at higher prices in 2008 to serve increased retail customer load, (ii) an increase of $5.5 million due to higher volumes of natural gas purchased at higher prices in 2008 to serve increased retail customer load, and (iii) an increase of $3.8 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	$	191.4	$	170.7	$	20.7
Conectiv Energy		30.0		26.8		3.2
Pepco Energy Services		22.2		19.3		2.9
Other Non-Regulated		1.0		.5		.5
Corp. & Other		(2.8)		(3.0)		.2
Total	$	241.8	$	214.3	$	27.5

Other Operation and Maintenance expenses of the Power Delivery segment increased by $20.7 million primarily due to (i) $10.6 million increase in costs associated with Default Electricity Supply primarily due to a higher rate of recovery of bad debt expenses (partially offset in Default Supply Revenue) as further discussed below, (ii) $4.7 million increase in employee-related costs, primarily due to the recording of additional stock-based compensation expense as further discussed below, (iii) $2.8 million increase in Demand Side Management program costs (offset in Deferred Electric Service Costs), (iv) $2.4 million increase in regulatory expenses, (v) $2.2 million increase due to higher bad debt expenses (partially offset in Deferred Electric Service Cost), offset by (vi) $1.8 million decrease in accounting services related to tax consulting fees, and (vii) $1.6 million decrease in preventative maintenance and system operation costs.

In the third quarter of 2008, DPL recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to May 2006 where late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the three months ended September 30, 2008 of $3.8 million. In the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the Long-Term Incentive Plan (LTIP) which resulted in an understatement of stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in Other Operation and Maintenance expenses for the three months ended September 30, 2008 of $8.8 million. These adjustments are not considered material either individually or in the aggregate.

Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, decreased by $17.1 million to $12.0 million in 2008 from $29.1 million in 2007. The decrease was primarily due to (i) $26.9 million decrease due to a lower rate of recovery of costs associated with energy and capacity purchased under the NUG contracts, partially offset by (ii) $9.5 million increase due to a higher rate of recovery associated with deferred transmission costs.

Depreciation and Amortization

Depreciation and Amortization expenses increased by $11.7 million to $99.3 million in 2008, from $87.6 million in 2007. The increase was primarily due to higher amortization by

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ACE of stranded costs as the result of an October 2007 Transition Bond Charge rate increase (offset in Default Supply Revenue).

Effect of Settlement of Mirant Bankruptcy Claims

The Effect of Settlement of Mirant Bankruptcy Claims reflects the recovery, in 2007, of $33.4 million in operating expenses and certain other costs as damages in the Mirant bankruptcy settlement.

Other Income (Expense)

Other Expenses (which are net of Other Income) increased by $3.0 million to a net expense of $75.9 million in 2008 from a net expense of $72.9 million in 2007 primarily due to (i) $1.5 million decrease in Contribution in Aid of Construction tax gross-ups, and (ii) $.9 million increase in unrealized loss on investments in certain trusts maintained to secure the payment of deferred compensation.

Income Tax Expense

During the second quarter 2008, PHI reached a tentative settlement with the Internal Revenue Service concerning the treatment by Pepco, DPL and ACE of mixed service construction costs for income tax purposes during the period 2001 to 2004. See “Commitments and Contingencies — Regulatory and Other Matters — IRS Mixed Service Cost Issue” in Note (13).

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The following results of operations discussion is for the nine months ended September 30, 2008, compared to the nine months ended September 30, 2007. All amounts in the tables (except sales and customers) are in millions.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Operating Revenue

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

	2008		2007		Change
Power Delivery	$	4,259.3	$	4,033.7	$	225.6
Conectiv Energy		2,395.2		1,607.5		787.7
Pepco Energy Services		1,967.7		1,686.9		280.8
Other Non-Regulated		(72.7)		58.0		(130.7)
Corp. & Other		(330.9)		(352.7)		21.8
Total Operating Revenue	$	8,218.6	$	7,033.4	$	1,185.2

Power Delivery Business

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

		2008		2007	Change
Regulated T&D Electric Revenue	$	1,301.9	$	1,206.4	$	95.5
Default Supply Revenue		2,657.7		2,557.8		99.9
Other Electric Revenue		48.0		48.3		(.3)
Total Electric Operating Revenue		4,007.6		3,812.5		195.1

Regulated Gas Revenue		146.3		161.4		(15.1)
Other Gas Revenue		105.4		59.8		45.6
Total Gas Operating Revenue		251.7		221.2		30.5

Total Power Delivery Operating Revenue	$	4,259.3	$	4,033.7	$	225.6

Regulated 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.

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

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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 by the 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 as part of Deferred Electric Service Costs pending an adjustment of retail rates in a future proceeding. As a consequence of the order, 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.

Electric Operating Revenue

Regulated T&D Electric Revenue		2008		2007	Change
Residential	$	450.0	$	452.0	$	(2.0)
Commercial		569.3		547.3		22.0
Industrial		21.1		19.3		1.8
Other		261.5		187.8		73.7
Total Regulated T&D Electric Revenue	$	1,301.9	$	1,206.4	$	95.5

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Regulated T&D Electric Sales (GWh)	2008		2007		Change
Residential		13,324		13,983		(659)
Commercial		21,926		22,129		(203)
Industrial		2,857		2,994		(137)
Other		185		185		-
Total Regulated T&D Electric Sales		38,292		39,291		(999)

Regulated T&D Electric Customers (in thousands)	2008	2007	Change
Residential	1,605	1,616		(11)
Commercial	196	197		(1)
Industrial	2	2		-
Other	2	2		-
Total Regulated T&D Electric Customers	1,805	1,817		(12)

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 $95.5 million primarily due to the following; (i) $37.3 million increase in Other Regulated T&D Electric Revenue from the resale of energy and capacity purchased under the Panda PPA (offset in Fuel and Purchased Energy and Other Services Cost of Sales), (ii) $25.5 million increase due to a distribution rate change under the 2007 Maryland Rate Orders that became effective in June 2007, including a positive $16.4 million Revenue Decoupling Adjustment, (iii) $19.9 million increase in transmission service revenue primarily due to changes in the FERC formula rates in June 2008 and 2007, (iv) $16.9 million increase due to District of Columbia distribution rate change that became effective in February 2008, (v) $14.8 million increase due to a distribution rate change as part of a higher New Jersey Societal Benefit Charge that became effective in June 2008, (offset in Deferred Electric Service Costs), (vi) $5.8 million increase due to differences in consumption among the various customer rate classes, partially offset by (vii) $14.4 million decrease due to lower weather-related sales (a 11% decrease in Heating Degree Days and a 4% decrease in Cooling Degree Days), and (viii) $9.3 million decrease due to the sale of DPL’s Virginia retail electric distribution business.

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Default Electricity Supply

Default Supply Revenue		2008		2007	Change
Residential	$	1,460.7	$	1,442.3	$	18.4
Commercial		866.1		829.0		37.1
Industrial		61.9		69.6		(7.7)
Other		269.0		216.9		52.1
Total Default Supply Revenue	$	2,657.7	$	2,557.8	$	99.9

Other Default Supply Revenue consists primarily of revenue from the resale of energy and capacity purchased under NUGs in the PJM RTO market.

Default Electricity Supply Sales (GWh)	2008	2007	Change
Residential	12,901	13,616		(715)
Commercial	7,351	7,629		(278)
Industrial	503	695		(192)
Other	72	102		(30)
Total Default Electricity Supply Sales	20,827	22,042		(1,215)

Default Electricity Supply Customers (in thousands)	2008	2007	Change
Residential	1,564	1,585		(21)
Commercial	166	169		(3)
Industrial	1	1		-
Other	2	2		-
Total Default Electricity Supply Customers	1,733	1,757		(24)

Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales and Deferred Electric Service Costs, increased by $99.9 million primarily due to the following; (i) $149.3 million increase in market-based Default Electricity Supply rates, (ii) $62.8 million increase in wholesale energy revenues due to the sale in PJM RTO at higher market prices of electricity purchased from NUGs, partially offset by (iii) $43.3 million decrease due to lower weather-related sales (a 11% decrease in Heating Degree Days and a 4% decrease in Cooling Degree Days), (iv) $25.3 million decrease primarily due to commercial and industrial customers electing to purchase an increased amount of electricity from competitive suppliers, (v) $24.2 million decrease due to the sale of DPL’s Virginia retail electric distribution business and (vi) $10.5 million decrease due to differences in consumption among the various customer rate classes.

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Gas Operating Revenue

Regulated Gas Revenue		2008		2007	Change
Residential	$	86.1	$	94.6	$	(8.5)
Commercial		49.8		55.7		(5.9)
Industrial		4.7		6.7		(2.0)
Transportation and Other		5.7		4.4		1.3
Total Regulated Gas Revenue	$	146.3	$	161.4	$	(15.1)

Regulated Gas Sales (Bcf)	2008	2007	Change
Residential	5.2	5.6		(.4)
Commercial	3.3	3.6		(.3)
Industrial	.4	.6		(.2)
Transportation and Other	5.3	4.9		.4
Total Regulated Gas Sales	14.2	14.7		(.5)

Regulated Gas Customers (in thousands)	2008	2007	Change
Residential	112	112		-
Commercial	10	9		1
Industrial	-	-		-
Transportation and Other	-	-		-
Total Regulated Gas Customers	122	121		1

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

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

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

Regulated Gas Revenue decreased by $15.1 million primarily due to (i) $7.3 million decrease due to Gas Cost Rate changes effective April 2007 and November 2007 (offset in Fuel and Purchased Energy and Other Services Cost of Sales), (ii) $6.4 million decrease due to lower weather-related sales (a 9% decrease in Heating Degree Days), (iii) $3.9 million decrease due to differences in consumption among the various customer rate classes, partially offset by (iv) $2.4 million increase due to a distribution base rate change effective in April 2007.

Other Gas Revenue

Other Gas Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales, increased by $45.6 million primarily due to higher off-system sales of which (i) $32.4 million was attributable to an increase in market prices, and (ii) $13.8 million was attributable to an increase in demand from electric generators and gas marketers that DPL

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was able to fulfill due to available pipeline capacity. Higher available capacity resulted from lower demand for natural gas from regulated customers caused by warmer weather in 2008 than 2007.

Competitive Energy Businesses

Conectiv Energy

Conectiv Energy Gross Margin

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Conectiv Energy Gross Margin and Operating Statistics	Nine Months Ended September 30,				Change
		2008		2007
Operating Revenue ($ millions):
Merchant Generation & Load Service	$	1,436.0	$	788.4		$	647.6
Energy Marketing		959.2		819.1			140.1
Total Operating Revenue1	$	2,395.2	$	1,607.5		$	787.7

Cost of Sales ($ millions):
Merchant Generation & Load Service	$	1,123.1	$	574.0		$	549.1
Energy Marketing		918.7		790.7			128.0
Total Cost of Sales2	$	2,041.8	$	1,364.7		$	677.1

Gross Margin ($ millions):
Merchant Generation & Load Service	$	312.9	$	214.4		$	98.5
Energy Marketing		40.5		28.4			12.1
Total Gross Margin	$	353.4	$	242.8		$	110.6

Generation Fuel and Purchased Power Expenses ($ millions) 3:
Generation Fuel Expenses 4,5
Natural Gas	$	199.0	$	201.4		$	(2.4)
Coal		45.0		46.6			(1.6)
Oil		25.7		24.6			1.1
Other6		1.3		1.8			(.5)
Total Generation Fuel Expenses	$	271.0	$	274.4		$	(3.4)
Purchased Power Expenses 5	$	741.6	$	353.1		$	388.5

Statistics:
Generation Output (MWh):
Base-Load 7		1,371,003		1,654,766			(283,763)
Mid-Merit (Combined Cycle) 8		2,281,981		2,534,378			(252,397)
Mid-Merit (Oil Fired) 9		64,720		174,277			(109,557)
Peaking		75,838		96,917			(21,079)
Tolled Generation		100,396		112,230			(11,834)
Total		3,893,938		4,572,568			(678,630)

Load Service Volume (MWh) 10		8,175,573		5,488,076			2,687,497

Average Power Sales Price 11 ($/MWh):
Generation Sales 4	$	117.77	$	83.22		$	34.55
Non-Generation Sales 12	$	91.67	$	69.81		$	21.86
Total	$	99.12	$	74.07		$	25.05

Average on-peak spot power price at PJM East Hub ($/MWh) 13	$	100.40	$	77.00		$	23.40
Average around-the-clock spot power price at PJM East Hub ($/MWh) 13	$	84.10	$	62.97		$	21.13
Average spot natural gas price at market area M3 ($/MMBtu)14	$	10.65	$	7.78		$	2.87

Weather (degree days at Philadelphia Airport): 15
Heating degree days		2,744		3,031			(287)
Cooling degree days		1,335		1,403			(68)

1	Includes $310.6 million and $334.9 million of affiliate transactions for 2008 and 2007, respectively.

2	Includes $5.7 million and $5.4 million of affiliate transactions for 2008 and 2007, respectively. Also, excludes depreciation and amortization expense of $27.8 million and $27.9 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.

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 margins were favorably impacted by volatile energy commodity prices in 2008. High energy commodity prices combined with volatility also contributed to significant movements in the value of transactions accounted for at fair value.

Merchant Generation & Load Service gross margin increased approximately $99 million primarily due to:

An increase of approximately $37 million primarily due to short-term sales of firm natural gas, and natural gas transportation and storage rights, the dual-fuel capability of the combined cycle mid-merit units (fuel switching), cross-commodity hedging (use of natural gas to hedge power positions), and the opportunities created by the mid-merit combined cycle units’ operating flexibility (option value) in conjunction with short-term power and fuel price volatility. This combination of strategies positioned Conectiv Energy to realize the upside potential of its overall portfolio during the winter period. The magnitude of gain was due partly to significant fuel price increases in conjunction with less significant increases in power prices.

·	An increase of approximately $33 million due to higher PJM capacity prices net of capacity hedges.

·	An increase of approximately $19 million due to the application of fair value accounting treatment and associated settlements with respect to excess coal hedges.

Energy Marketing gross margin increased approximately $12 million primarily due to:

·	An increase of approximately $7 million in short-term power desk margins in 2008.

·	An increase of approximately $6 million due to additional default electricity supply contracts in 2008.

Pepco Energy Services

Pepco Energy Services’ operating revenue increased $280.8 million primarily due to (i) an increase of $212.5 million due to higher volumes of retail electric load served at higher prices in 2008 due to customer acquisitions, (ii) an increase of $56.1 million due to higher natural gas volumes due to customer acquisitions and also higher prices in 2008, and (iii) an increase of $12.2 million due to more construction activities in 2008.

Other Non-Regulated

Other Non-Regulated revenues decreased by $130.7 million from $58.0 million for the nine months ended September 30, 2007 to $(72.7) million for the nine months ended

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September 30, 2008. A non-cash charge of $124.4 million was recorded during the second quarter of 2008 as a result of revised assumptions regarding the estimated timing of tax benefits from PCI’s cross-border energy lease investments. In accordance with FSP 13-2, this charge was recorded as a reduction to lease revenue from these transactions, which is included in Other Non-Regulated revenues.

Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2008		2007		Change
Power Delivery	$	2,775.6	$	2,612.3	$	163.3
Conectiv Energy		2,041.8		1,364.7		677.1
Pepco Energy Services		1,851.9		1,586.2		265.7
Corporate and Other		(327.2)		(349.9)		22.7
Total	$	6,342.1	$	5,213.3	$	1,128.8

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy and Other Services Cost of Sales, which is primarily associated with Default Electric Supply sales, increased by $163.3 million primarily due to (i) $240.4 million increase in average energy costs, the result of new Default Electricity Supply contracts, (ii) $43.3 million increase due to gas purchases for off-system sales, (iii) $37.3 million increase for energy and capacity purchased under the Panda PPA (offset in Regulated T&D Electric Revenue), partially offset by (iv) $55.8 million decrease due to differences in consumption among various customer rate classes, (v) $47.2 million decrease due to lower weather-related sales, (vi) $35.7 million decrease due to the sale of DPL’s Virginia retail electric distribution business including the transfer of its Default Supply obligations, (vii) $8.5 million decrease due to a lower rate of recovery of natural gas supply costs resulting in a change in the Deferred Gas Fuel balance, and (viii) $7.1 million decrease due to a lower rate of recovery of electricity supply costs resulting in a change in the Default Electricity Supply deferral balance. Fuel and Purchased Energy expense is substantially offset in Default Supply Revenue, Regulated Gas Revenue, and Other Gas Revenue.

Competitive Energy Business

Conectiv Energy

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Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales increased $265.7 million primarily due to (i) an increase of $204.6 million due to higher volumes of purchased electricity at higher prices in 2008 to serve increased retail customer load, (ii) an increase of $48.1 million due to higher volumes of natural gas purchased at higher prices in 2008 to serve increased retail customer load, and (iii) an increase of $13.0 million due to increased construction activities in 2008.

Other Operation and Maintenance

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

	2008		2007		Change
Power Delivery	$	535.3	$	488.8	$	46.5
Conectiv Energy		105.5		94.9		10.6
Pepco Energy Services		62.1		54.8		7.3
Other Non-Regulated		1.9		3.0		(1.1)
Corporate and Other		(13.4)		(9.3)		(4.1)
Total	$	691.4	$	632.2	$	59.2

Other Operation and Maintenance expenses of the Power Delivery segment increased by $46.5 million; however, excluding a 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 $49.9 million. The $49.9 million increase was primarily due to (i) $19.2 million increase in costs associated with Default Electricity Supply primarily due to a higher rate of recovery of bad debt expenses (partially offset in Default Supply Revenue) as further discussed below, (ii) $9.6 million increase in employee-related costs, primarily due to the recording of additional stock-based compensation expense as further discussed below, (iii) $6.1 million increase due to higher bad debt expenses (partially offset in Deferred Electric Service Costs), (iv) $5.1 million increase in preventative maintenance and system operation costs, (v) $4.4 million increase in expenses related to Blueprint for the Future and Mid-Atlantic Power Pathway Projects, (vi) $4.2 million increase in Demand Side Management program costs (offset in Deferred Electric Service Costs), (vii) $3.4 million increase primarily due to recovery of stranded costs in 2007, (viii) $2.1 million increase in customer service operation expenses, partially offset by (ix) $3.7 million decrease in regulatory expenses, (x) $3.4 million decrease due to various construction project write-offs in 2007 related to customer requested work, and (xi) $2.5 million decrease in accounting services related to tax consulting fees.

In the second quarter of 2008, Pepco recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to February 2005 where late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $3.3 million. In the third quarter of 2008, DPL also recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to May 2006 where late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $2.8 million. In the third quarter of 2008, PHI identified an error in the accounting for certain of its

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restricted stock awards granted under the Long-Term Incentive Plan which resulted in an understatement of stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $8.8 million. These adjustments are not considered material either individually or in the aggregate.

The higher operation and maintenance expenses of the Conectiv Energy segment in 2008 were primarily due to increased planned maintenance at its power plants.

The higher operation and maintenance expenses of the Pepco Energy Services segment in 2008 were primarily due to increased compensation and benefits costs related to growth in its businesses.

Depreciation and Amortization

Depreciation and amortization expenses increased by $9.5 million to $282.9 million in 2008 from $273.4 million in 2007. The increase was primarily due to (i) $22.1 million higher amortization by ACE of stranded costs as the result of an October 2007 Transition Bond Charge rate increase (offset in Default Supply Revenue), partially offset by (ii) $15.6 million decrease in depreciation due to a change in depreciation rates in accordance with the 2007 Maryland Rate Order.

Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, decreased by $27.2 million to $20.0 million in 2008 from $47.2 million in 2007. The decrease was primarily due to (i) $42.8 million decrease due to a lower rate of recovery associated with deferred energy costs, partially offset by (ii) $13.1 million increase due to a higher rate of recovery of costs associated with energy and capacity purchased under the NUG contracts, and (iii) $2.5 million increase due to a higher rate of recovery associated with deferred transmission costs.

Effect of Settlement of Mirant Bankruptcy Claims

The Effect of Settlement of Mirant Bankruptcy Claims reflects the recovery, in 2007, of $33.4 million in operating expenses and certain other costs as damages in the Mirant bankruptcy settlement.

Other Income (Expense)

Other Expenses (which are net of Other Income) increased by $5.8 million to a net expense of $218.2 million in 2008 from a net expense of $212.4 million in 2007 primarily due to a $3.9 million decrease in Contribution in Aid of Construction tax gross-ups.

Income Tax Expense

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increase in tax benefits related to changes in estimates and interest related to uncertain and effectively settled tax positions.

During the second quarter 2008, PHI reached a tentative settlement with the Internal Revenue Service concerning the treatment by Pepco, DPL and ACE of mixed service construction costs for income tax purposes during the period 2001 to 2004. On the basis of the tentative settlement, PHI updated its estimated liability related to mixed service costs and as a result, recorded a net reduction in its liability for unrecognized tax benefits of $18.7 million and recognized after-tax interest income of $7.2 million in the second quarter of 2008. See “Commitments and Contingencies—Regulatory and Other Matters — IRS Mixed Service Cost Issue” in Note (13).

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 September 30, 2008, Pepco Holdings’ current assets on a consolidated basis totaled $2.5 billion and its current liabilities totaled $2.6 billion. At December 31, 2007, Pepco Holdings’ current assets totaled $2.0 billion and its current liabilities totaled $2.0 billion. The decrease in working capital from December 31, 2007 to September 30, 2008 is primarily due to an increase in short-term debt, partially offset by the proceeds from long-term debt issuances in March 2008.

At September 30, 2008, Pepco Holdings’ cash and current cash equivalents totaled $227.2 million, of which $190.9 million was invested in money market funds that invest in U.S. Treasury obligations, and the balance was held as cash and uncollected funds. Current restricted cash (cash that is available to be used only for designated purposes) totaled $45.4 million. At December 31, 2007, Pepco Holdings’ cash and current cash equivalents totaled $55.1 million and its current restricted cash totaled $14.5 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 September 30, 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	$ 1.0	$ -	$ -	$24.3	$ -	$-	$130.1
Bonds held under Standby Bond Purchase Agreement	-	-	-	21.6	-	-	-	-	-	21.6
Commercial Paper	-	42.7	13.9	61.6	-	-	-	-	-	118.2
Bank Loans	-	25.0	150.0	-	-	-	-	-	-	175.0
Credit Facility	200.0	100.0	-	135.0	-	-	-	-	-	435.0
Total Short-Term Debt	$200.0	$167.7	$268.7	$219.2	$ -	$ -	$24.3	$ -	$-	$879.9

Current Maturities of Long-Term Debt and Project Funding	$ -	$100.0	$ -	$ -	$31.9	$ -	$ 2.3	$92.0	$-	$226.2

	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 September 30, 2008

As a result of severe liquidity constraints in the credit, commercial paper and capital markets during September 2008, PHI, Pepco, and ACE borrowed under their $1.5 billion credit facility (described below). Typically, the companies issue commercial paper as required to meet their short term working capital requirements. Given the lack of liquidity in the commercial paper markets, the companies borrowed under the credit facility to create a cash reserve for future short-term operating needs. At September 30, 2008, PHI borrowed $200 million, Pepco borrowed $100 million, and ACE borrowed $135 million. These LIBOR-based loans matured during October 2008 and were rolled to November 2008. The companies expect to continue to roll the loans monthly until they are able to resume funding in the commercial paper market or access other funding in the capital markets.

·	In July 2008, DPL amended its $150 million loan agreement to convert it from a two-year loan into a 364-day loan that matures in July 2009.

·	In July 2008, ACE Funding made principal payments of $2.6 million on Series 2002-1 Bonds, Class A-1, $2.3 million on Series 2002-1 Bonds, Class A-2, and $1.9 million on Series 2003-1 Bonds, Class A-1.

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In August 2008, DPL repurchased, on the mandatory put date, $18.2 million of Exempt Facilities Revenue Bonds, 2003B Series, due 2023, issued by the Delaware Economic Development Authority for the benefit of DPL. The bonds are considered to be extinguished for accounting purposes, although they remain outstanding, registered in DPL’s name, pending a decision by DPL to resell or retire the bonds.

·	In September 2008, Pepco repaid at maturity a $25 million short-term loan.

Financing Activity Subsequent to September 30, 2008

·	In October 2008, ACE Funding made principal payments of $6.7 million on Series 2002-1 Bonds, Class A-2, and $2.7 million on Series 2003-1 Bonds, Class A-1.

·	In October 2008, Pepco redeemed $50 million of 5.875% first mortgage bonds at maturity.

·	In October 2008, PHI borrowed an additional $50 million under its credit facility, Pepco borrowed an additional $100 million and DPL borrowed $150 million.

Credit Facility

PHI, Pepco, DPL and ACE maintain a credit facility to provide for their respective short-term liquidity needs.

The aggregate borrowing limit under the facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI's credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million. The interest rate payable by each company on utilized funds is based on the prevailing prime rate or Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. The facility also includes a "swingline loan sub-facility" pursuant to which each company may make same day borrowings in an aggregate amount not to exceed $150 million. Any swingline loan must be repaid by the borrower within seven days of receipt thereof. All indebtedness incurred under the facility is unsecured.

The facility commitment expiration date is May 5, 2012, with each company having the right to elect to have 100% of the principal balance of the loans outstanding on the expiration date continued as non-revolving term loans for a period of one year from such expiration date.

The facility is intended to serve primarily as a source of liquidity to support the commercial paper programs of the respective companies. The companies also are permitted to

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use the facility to borrow funds for general corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain sales and dispositions, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The absence of a material adverse change in the borrower’s business, property, and results of operations or financial condition is not a condition to the availability of credit under the facility. The credit agreement does not include any rating triggers.

Cash and Credit Facility Available as of September 30, 2008

	Consolidated PHI		PHI Parent		Utility Subsidiaries

Credit Facility (Total Capacity)	$	1,500.0	$	875.0	$	625.0
Credit Facility Borrowings		(435.0)		(200.0)		(235.0)
Letters of Credit		(350.9)		(346.0)		(4.9)
Commercial Paper Outstanding		(118.2)		-		(118.2)
Remaining Credit Facility Available		595.9		329.0		266.9
Cash Invested in Money Market Funds (a)		190.9		150.1		40.8
Total Cash and Credit Facility Available	$	786.8	$	479.1	$	307.7

(a)	Cash and cash equivalents reported on the Balance Sheet total $227.2 million, which includes the $190.9 million invested in money market funds and $36.3 million held in cash and uncollected funds.

During the month of October 2008, PHI’s consolidated cash and credit facility available ranged from a low of $380 million to a high of $847 million, and averaged $601 million. The utility subsidiaries’ cash and credit facility available ranged from a low of $178 million to a high of $350 million, and averaged $286 million.

Cash Flow Activity

PHI’s cash flows for the nine months ended September 30, 2008 and 2007 are summarized below.

	Cash Source / (Use)
		2008		2007
		(Millions of dollars)
Operating activities	$	468.8	$	462.5
Investing activities		(537.8)		(391.8)
Financing activities		241.1		(93.5)
Net increase (decrease) in cash and cash equivalents	$	172.1	$	(22.8)

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Operating Activities

Cash flows from operating activities during the nine months ended September 30, 2008 and 2007 are summarized below.

	Cash Source / (Use)
		2008		2007
		(Millions of dollars)
Net income	$	233.0	$	276.4
Non-cash adjustments to net income		689.9		300.8
Changes in working capital		(454.1)		(114.7)
Net cash from operating activities	$	468.8	$	462.5

Net cash from operating activities was $6.3 million higher for the nine months ended September 30, 2008, compared to the same period in 2007. Net income is lower in 2008 primarily as a result of the second quarter non-cash charge related to the cross border energy leases, however, net income from PHI’s core business operations has increased, resulting in an increase in PHI’s net cash from operating activities. This is partially offset by the cash collateral requirements associated with Competitive Energy activities. Cash collateral requirements may fluctuate significantly based on changing energy market prices.

In addition, as further discussed in “Commitments and Contingencies ¾ Proceeds from Settlement of Mirant Bankruptcy Claims” in Note (13), non-cash charges to net income and changes in working capital have increased during the nine months ended September 30, 2008 because of the transfer by Pepco to Sempra Energy Trading LLC of the Panda PPA.

Investing Activities

Cash flows from investing activities during the nine months ended September 30, 2008 and 2007 are summarized below.

	Cash (Use) / Source
		2008		2007
		(Millions of dollars)
Construction expenditures	$	(560.6)	$	(422.7)
Cash proceeds from sale of other assets		51.5		10.6
Changes in restricted cash		(30.9)		4.9
All other investing cash flows, net		2.2		15.4
Net cash used by investing activities	$	(537.8)	$	(391.8)

Net cash used by investing activities increased $146.0 million for the nine months ended September 30, 2008 compared to the same period in 2007. The increase was due in part to (i) $137.9 million increase in capital expenditures of which $59.7 million was attributable to Conectiv Energy and $54.5 million was attributable to Power Delivery and (ii) $35.8 million increase in the use of restricted cash, offset by (iii) an increase of $40.9 million in cash proceeds from the sale of assets. The increase in Conectiv Energy capital expenditures was primarily due to the construction of new generation plants. The increase in Power Delivery capital expenditures was primarily attributable to capital costs associated with new customer services,

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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 distribution assets. 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. The increased use of restricted cash was the result of an increase in performance bid collateral held by DPL and Pepco which ensures that suppliers will supply energy in the future to DPL and Pepco.

Financing Activities

Cash flows from financing activities during the nine months ended September 30, 2008 and 2007 are summarized below.

	Cash (Use) / Source
		2008		2007
		(Millions of dollars)
Dividends paid on common and preferred stock	$	(163.2)	$	(150.8)
Common stock issued for the Dividend Reinvestment Plan		24.8		21.0
Issuance of common stock		14.8		23.9
Redemption of preferred stock of subsidiaries		-		(18.2)
Issuances of long-term debt		400.0		452.8
Reacquisition of long-term debt		(437.8)		(670.8)
Issuances of short-term debt, net		441.1		246.6
All other financing cash flows, net		(38.6)		2.0
Net cash from (used by) financing activities	$	241.1	$	(93.5)

Net cash from financing activities increased $334.6 million for the nine months ended September 30, 2008, compared to the same period in 2007.

Changes in Outstanding Common Stock. Proceeds from the issuance of stock decreased in the 2008 period due to a decrease in stock options exercised. Under the Shareholder Dividend Reinvestment Plan, PHI issued 881,443 shares of common stock during the nine months ended September 30, 2008, as compared to 742,407 shares issued during the nine months ended September 30, 2007. Under the Long-Term Incentive Plan, PHI issued 548,216 shares of common stock during the nine months ended September 30, 2008, and 527,730 shares of common stock during the nine months ended September 30, 2007.

Common Stock Dividend. Common stock dividend payments were $163.0 million in the first nine months of 2008 and $150.5 million in the first nine months of 2007. The increase in common dividends paid in 2008 was the result of additional shares outstanding (primarily from PHI’s 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 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,

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·	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 Long-Term Debt. Cash flows from the issuance and reacquisition of long-term debt in the third quarter of 2008 were attributable primarily to the transactions described under the heading “Financing Activity During the Three Months Ended September 30, 2008” above. Cash flows from the issuance and reacquisition of long-term debt in the first and second quarters of 2008 were attributable primarily to the following transactions:

·	In January 2008, 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.

In March 2008, Pepco retired at maturity $78 million of 6.5% first mortgage bonds.

In March 2008, DPL entered into a $150 million, unsecured two-year bank loan agreement. In July, this loan was converted into a 364-day loan maturing July 2009.

·	In April 2008, Atlantic City Electric Transition Funding LLC (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.

In May 2008, Pepco entered into the following loan transactions:

·	A 364-day $25 million loan that matures on April 30, 2009. Interest on the loan is calculated based on the prevailing Eurodollar rate for the applicable interest period, plus 0.60% per annum.

·	A $25 million loan that matures on September 30, 2008. Interest on the loan is calculated based on the prevailing Eurodollar rate for the applicable interest period, plus 0.60% per annum.

·	In June 2008, DPL redeemed $4.36 million 6.95% first mortgage bonds at maturity.

During the first and second quarters of 2008, PHI subsidiaries purchased at par insured tax-exempt auction rate bonds issued by municipal authorities for the benefit of the respective

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PHI subsidiaries in the aggregate principal amount of $257.6 million. 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. The bonds purchased during the first three quarters of 2008 consisted of the following:

In March 2008, 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.

·	In March 2008, ACE purchased $25 million of Pollution Control Revenue Refunding Bonds 2004A Series due 2029 issued by Cape May County.

·	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.

·	In April 2008, ACE purchased the following series of bonds: (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.

After giving effect to these repurchases, the aggregate principal amount of tax-exempt auction rate bonds held by PHI subsidiaries at September 30, 2008, is as follows (dollars in millions):

	Pepco	$109.5
	DPL	$111.6
	ACE	$ 54.7

These tax-exempt auction rate bonds are 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 at some time in the future.

In the third quarter of 2008, ACE Funding made principal payments of $2.6 million on Series 2002-1 Bonds, Class A-1, $2.3 million on Series 2002-1 Bonds, Class A-2, and $1.9 million on Series 2003-1 Bonds, Class A-1.

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In June 2008, the holders of the following insured Variable Rate Demand Bonds (VRDBs), in accordance with the terms thereof, tendered the bonds to The Bank of New York, as bond trustee, for purchase at par:

·	$13.4 million of Pollution Control Revenue Refunding Bonds 1997 Series A issued by Salem County for the benefit of ACE, and

·	$4.4 million of Pollution Control Revenue Refunding Bonds 1997 Series B issued by Salem County for the benefit of ACE.

The payment for these VRDBs was financed by The Bank of New York under Standby Bond Purchase Agreements (SBPAs) for the respective series. If these VRDBs cannot be remarketed by the remarketing agent prior to the first anniversary of the purchase of the VRDBs by the bond trustee, ACE will be obligated to redeem 1/10th of the principal amount of each series of VRDBs held by the bond trustee every six months thereafter. While the VRDBs are held by the bond trustee, ACE is obligated to pay interest on such bonds at a rate equal to the prime rate or Libor plus 50 basis points.

During the first and second quarters of 2008, ACE redeemed at maturity the following Medium Term Notes:

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

·	In April 2008, $1 million of 6.77% Medium Term Notes.

·	In May 2008, (i) $21 million of 6.75% Medium Term Notes and (ii) $4 million of 6.73% Medium Term Notes.

·	In June 2008, (i) $4 million of 6.73% Medium Term Notes and (ii) $5 million of 6.71% Medium Term Notes.

Cash flows from the issuance and reacquisition of long-term debt during the first three quarters of 2007 were attributable primarily to the following transactions:

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

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

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

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

In April 2007, PHI issued $200 million of 6.0% notes due 2019 in a private placement. Proceeds were used to redeem, on May 31, 2007, $200 million of 5.5% notes due August 15, 2007 at a price of 100.0377% of par.

In April 2007, ACE retired at maturity $15 million of 7.52% medium-term notes.

In April 2007, ACE Funding made principal payments of $4.9 million on Series 2002-1 Transition Bonds, Class A-1 and $2.0 million on Series 2003-1 Transition Bonds, Class A-1 with a weighted average interest rate of 2.89%.

In May 2007, DPL retired at maturity $50 million of 8.125% medium-term notes.

In June 2007, PHI issued $250 million of 6.125% notes due 2017 in a public offering. Net proceeds along with short-term debt were used to repay $300 million of 5.5% notes due August 15, 2007.

In June 2007, DPL retired at maturity $3.2 million of 6.95% first mortgage bonds.

·	In July 2007, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $4.8 million on Series 2002-1 Transition Bonds, Class A-1 and $1.8 million on Series 2003-1 Transition Bonds, Class A-1 with a weighted average interest rate of 2.89%.

·	In August 2007, PHI paid at maturity $300 million of 5.5% notes using the proceeds of a June 2007 offering of $250 million of 6.125% ten-year notes and short-term debt.

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 the first quarter of 2008, Pepco and DPL redeemed $108.0 million in short-term debt with cash from capital contributions. During the first and second quarter, ACE issued $78 million of commercial paper. In May 2008, Pepco entered into the following loan transactions:

·	A 364-day $25 million bank loan that matures on April 30, 2009. Interest on the loan is calculated based on the prevailing Eurodollar rate for the applicable interest period, plus 0.60% per annum.

·	A $25 million bank loan that matured on September 30, 2008. Interest on the loan was calculated based on the prevailing Eurodollar rate for the applicable interest period, plus 0.60% per annum.

Due to the liquidity constraints in the commercial paper market in September, PHI borrowed $200 million, Pepco borrowed $100 million, and ACE borrowed $135 million under their $1.5 billion credit facility.

Issuances of short-term debt in 2007 were used to finance short-term liquidity needs and temporarily fund redemptions of long-term debt.

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Capital Requirements

Capital Expenditures

Pepco Holdings' total capital expenditures for the nine months ended September 30, 2008 totaled $560.6 million, of which $201.9 million was incurred by Pepco, $108.5 million was incurred by DPL, $121.8 million was incurred by ACE and $89.7 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. The MAPP Project will primarily be located in the Pepco and DPL service territory. 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 $400 million. These enhancements have been recommended to PJM, and if approved, will increase PHI’s projected costs associated with the MAPP Project.

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

For a discussion of PHI’s third party guarantees, indemnifications, obligations and off-balance sheet arrangements, see Note (13) “Commitments and Contingencies” to the Consolidated Financial Statements of PHI included in Part I, Item 1, in this Form 10-Q.

Dividends

On October 23, 2008, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable December 31, 2008, to shareholders of record on December 10, 2008.

Pension Funding

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

As of the 2008 valuation, the PHI Retirement Plan satisfied the minimum funding requirements of the Employment Retirement Income Security Act of 1974 (ERISA) without requiring any additional funding. PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level in excess of 100% of its accumulated benefit obligation (ABO).

The funded status of the PHI Retirement Plan is dependent upon many factors, including returns on invested assets and the level of market interest rates. As a result of losses experienced in global equity markets, the PHI Retirement Plan is likely to have a negative return for 2008, which in turn would create increased pension costs in 2009. PHI has made no cash contributions

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to the PHI Retirement Plan during the first nine months of 2008 and no contributions are expected to be made for the remainder of the year. With the volatility of the global equity markets and the capital and credit market disruptions, PHI will continue to evaluate the funding status of the PHI Retirement Plan in 2009 and the need for any contributions to maintain compliance with ERISA.

The PHI Retirement Plan has not experienced any significant impact on liquidity or counterparty exposure due to the volatility in the credit markets. Approximately 90% of the PHI Retirement Plan assets are invested in readily-liquid investments, including equity and debt securities. The balance of assets (10%) is invested in less liquid investments, including real estate and private equity funds.

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 Fair Value Energy Contract Net Assets (Liabilities) For the Nine Months Ended September 30, 2008 (Dollars are pre-tax and in millions)
	Energy Commodity Activities (a)
Total Fair Value Energy Contract Net Assets at December 31, 2007	$	18.1
Total change in unrealized fair value		44.9
Less: Reclassification to realized at settlement of contracts		(104.9)
Effective portion of changes in fair value - recorded in Other Comprehensive Income		(42.8)
Cash flow hedge ineffectiveness - recorded in earnings		(.8)
Total Fair Value Energy Contract Net Liabilities at September 30, 2008	$	(85.5)

Detail of Fair Value Energy Contract Net Liabilities at September 30, 2008 (see above)
Current Assets (unrealized gains - derivative contracts)	$	137.2
Noncurrent Assets (other assets)		24.3
Total Fair Value Energy Contract Assets		161.5
Current Liabilities (other current liabilities)		199.5
Noncurrent Liabilities (other liabilities)		47.5
Total Fair Value Energy Contract Liabilities		247.0
Total Fair Value Energy Contract Net Liabilities	$	(85.5)

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

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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 September 30, 2008 and are subject to change as a result of changes in these factors:

Maturity and Source of Fair Value of Energy Contract Net Assets (Liabilities) As of September 30, 2008 (Dollars are pre-tax and in millions)
	Fair Value of Contracts at September 30, 2008 Maturities
	2008		2009		2010		2011 and Beyond		Total Fair Value
Energy Commodity Activities, net (a)
Actively Quoted (i.e., exchange-traded) prices	$	4.1	$	5.6	$	(9.3)	$	4.3	$	4.7
Prices provided by other external sources (b)		(27.4)		(48.7)		(12.5)		(3.7)		(92.3)
Modeled (c)		2.1		-		-		-		2.1
Total	$	(21.2)	$	(43.1)	$	(21.8)	$	.6	$	(85.5)

Notes:
(a)	Includes all SFAS No. 133 hedge activity and trading activities recorded at fair value through AOCI or on the Statement of Earnings, as required.
(b)	Prices provided by other external sources reflect information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(c)	Modeled values include significant inputs, usually representing more than 10% of the valuation, not readily observable in the market. The modeled valuation above represents the fair valuation of certain coal transactions based on broker prices with a significant credit reserve applied.

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 September 30, 2008, a one-level downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries, which would decrease PHI's rating to below “investment grade,” would increase the collateral obligation of PHI and its subsidiaries by up to $403 million. PHI believes that it and its subsidiaries currently have sufficient liquidity to fund their operations and meet their financial obligations.

Many of the contractual arrangements entered into by PHI’s subsidiaries in connection with Competitive Energy and Default Electricity Supply activities include margining rights pursuant to which the PHI subsidiary or a counterparty may request collateral if the market value of the contractual obligations reaches levels in excess of the credit thresholds established in the applicable arrangements. Pursuant to these margining rights, the affected PHI subsidiary may receive, or be required to post, collateral due to energy price movements. As of September 30, 2008, Pepco Holdings’ subsidiaries engaged in Competitive Energy activities and Default Electricity Supply activities provided net cash collateral in the amount of $179.2 million in connection with these activities.

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REGULATORY AND OTHER MATTERS

For a discussion of material pending matters such as regulatory and legal proceedings, and other commitments and contingencies, see Note (13) “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, second or third quarters 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 Part I, 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 Pepco Holdings’ 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.

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

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

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

Weather conditions;

Population growth rates and demographic patterns;

Competition for retail and wholesale customers;

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

Growth in demand, sales and capacity to fulfill demand;

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

Changes in accounting standards or practices;

Changes in project costs;

Unanticipated changes in operating expenses and capital expenditures;

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

Rules and regulations imposed by Federal and/or state regulatory commissions, PJM and other regional transmission organizations (New York Independent System Operator, ISONE), the North American Electric Reliability 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 and capital market conditions; and

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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 September 30, 2008, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to Washington, D.C. customers.

In connection with its approval of new electric service distribution base rates for Pepco in Maryland, effective 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.

Impact of the Current Capital and Credit Market Disruptions

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Liquidity Requirements

Ongoing Monitoring of Financial and Market Conditions

Pepco monitors its liquidity position on a daily basis. Pepco also closely monitors its credit ratings and credit outlook and computes the hypothetical effect of changes in credit ratings on its cost of capital.

Pension and Postretirement Benefit Plans

Pepco participates in pension and postretirement benefit plans sponsored by PHI for employees. While the plans have not experienced any significant impact in terms of liquidity or counterparty exposure due to the disruption of the capital and credit markets, the recent stock market declines have caused a decrease in the market value of benefit plan assets over the nine months ended September 30, 2008. A negative return for the entire year will not have an impact

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on Pepco’s results of operations for 2008; however, such a reduction in benefit plan assets is likely to result in increased pension and postretirement benefit costs in future years.

RESULTS OF OPERATIONS

The accompanying results of operations discussion is for the nine months ended September 30, 2008, compared to the nine months ended September 30, 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	$	763.9	$	705.4	$	58.5
Default Supply Revenue		1,001.7		966.3		35.4
Other Electric Revenue		25.5		23.5		2.0
Total Operating Revenue	$	1,791.1	$	1,695.2	$	95.9

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 include 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	$	203.8	$	208.5	$	(4.7)
Commercial		417.5		403.4		14.1
Industrial		-		-		-
Other		142.6		93.5		49.1
Total Regulated T&D Electric Revenue	$	763.9	$	705.4	$	58.5

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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 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	5,991	6,332		(341)
Commercial	14,441	14,532		(91)
Industrial	-	-		-
Other	114	114		-
Total Regulated T&D Electric Sales	20,546	20,978		(432)

Regulated T&D Electric Customers (in thousands)	2008	2007	Change
Residential	688	683		5
Commercial	74	73		1
Industrial	-	-		-
Other	-	-		-
Total Regulated T&D Electric Customers	762	756		6

Regulated T&D Electric Revenue increased by $58.5 million primarily due to the following; (i) $37.3 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) $16.9 million increase due to a District of Columbia distribution rate change that became effective February, 2008, (iii) $13.6 million increase due to a distribution rate change under the 2007 Maryland Rate Order that became effective in June 2007, including a positive $10.3 million Revenue Decoupling Adjustment, partially offset by (iv) $9.2 million decrease due to lower weather-related sales (a 16% decrease in Heating Degree Days a 1% decrease in Cooling Degree Days).

Default Electricity Supply

Default Supply Revenue		2008		2007	Change
Residential	$	615.4	$	603.6	$	11.8
Commercial		381.1		356.5		24.6
Industrial		-		-		-
Other		5.2		6.2		(1.0)
Total Default Supply Revenue	$	1,001.7	$	966.3	$	35.4

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Default Electricity Supply Sales (GWh)	2008	2007	Change
Residential	5,665	6,016		(351)
Commercial	3,150	3,383		(233)
Industrial	-	-		-
Other	6	35		(29)
Total Default Electricity Supply Sales	8,821	9,434		(613)

Default Electricity Supply Customers (in thousands)	2008	2007	Change
Residential	655	657		(2)
Commercial	53	53		-
Industrial	-	-		-
Other	-	-		-
Total Default Electricity Supply Customers	708	710		(2)

Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy, increased by $35.4 million primarily due to the following; (i) $87.5 million increase in market based Default Electricity Supply rates, partially offset by (ii) $26.6 million decrease due to lower weather-related sales (a 16% decrease in Heating Degree Days and a 1% decrease in Cooling Degree Days), (iii) $21.3 million decrease primarily due to existing commercial customers electing to purchase an increased amount of electricity from competitive suppliers, and (iv) $4.9 million decrease primarily due to differences in consumption among the various customer rate classes.

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.

	2008	2007
Sales to District of Columbia customers	33%	36%
Sales to Maryland customers	50%	52%

Operating Expenses

Fuel and Purchased Energy

Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply sales, increased by $68.4 million to $1,033.2 million in 2008 from $964.8 million in 2007. The increase is primarily due to the following: (i) $107.7 million increase in average energy costs, the result of new Default Electricity Supply contracts, (ii) $37.3 million increase for energy and capacity purchased under the Panda PPA (offset in Regulated T&D Electric Revenue), partially offset by (iii) $31.9 decrease primarily due to commercial customers electing to purchase an increased amount of electricity from competitive suppliers, (iv) $27.9 million decrease due to lower weather-related sales, and (v) $13.2 million decrease due to a lower rate of recovery of electricity supply costs resulting in a change 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 increased by $6.2 million to $226.9 million in 2008 from $220.7 million in 2007. The increase was primarily due to the following: (i) $7.0 million increase in costs associated with Default Electricity Supply primarily due to a higher rate of recovery of bad debt expenses (substantially offset in Default Supply Revenue) as further discussed below, (ii) $4.6 million increase in employee-related costs, primarily due to the recording of additional stock-based compensation expense as further discussed below, (iii) $1.6 million increase in expenses related to Blueprint for the Future and Mid-Atlantic Power Pathway projects, (iv) $1.1 million increase due to higher bad debt expenses, (v) $.9 million increase in environmental costs related to spill prevention and handling of conduit materials, partially offset by (vi) $4.1 million decrease in regulatory expenses, (vii) $3.4 million decrease due to various construction project write-offs in 2007 related to customer requested work, and (viii) $3.0 million decrease in accounting services related to tax consulting fees.

In the second quarter of 2008, Pepco recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to February 2005 where late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $3.3 million. In the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the Long-Term Incentive Plan which resulted in an understatement of Pepco’s stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in Pepco’s Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $3.2 million. These adjustments are not considered material either individually or in the aggregate.

Depreciation and Amortization

Depreciation and Amortization expenses decreased by $12.5 million to $104.4 million in 2008 from $116.9 million in 2007. The decrease was primarily due to a change in depreciation rates in accordance with the 2007 Maryland Rate Order.

Effect of Settlement of Mirant Bankruptcy Claims

The Effect of Settlement of Mirant Bankruptcy Claims reflects the recovery, in 2007, of $33.4 million in operating expenses and certain other costs as damages in the Mirant bankruptcy settlement.

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $11.1 million to a net expense of $56.5 million in 2008 from a net expense of $45.4 million in 2007. This increase was primarily due to an increase in interest expense related to long-term debt.

Income Tax Expense

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During the second quarter 2008, Pepco reached a tentative settlement with the Internal Revenue Service concerning the treatment of mixed service costs for income tax purposes during the period 2001 to 2004. On the basis of the tentative settlement, Pepco updated its estimated liability related to mixed service costs and as a result, recorded a net reduction in its liability for unrecognized tax benefits of $15.8 million and recognized after-tax interest income of $2.7 million in the second quarter of 2008. See "Commitments and Contingencies — Regulatory and Other Matters — IRS Mixed Service Cost Issue” in Note (10).

Capital Requirements

Capital Expenditures

Pepco's capital expenditures for the nine months ended September 30, 2008, totaled $201.9 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. The MAPP Project will primarily be located in the Pepco and Delmarva Power & Light Company service territory. 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 the Chesapeake Bay, at an estimated cost of $400 million. These enhancements have been recommended to PJM, and if approved, will increase Pepco’s projected costs associated with the MAPP Project.

As further discussed in Note (7) “Debt” to the Pepco financial statements, PHI, Pepco, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE) maintain a credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under the facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI's credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million.

FORWARD-LOOKING STATEMENTS

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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 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:

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 influence Pepco’s business and profitability;

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

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Interest rate fluctuations and credit and capital market conditions; and

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

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

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

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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 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 1.3 million. As of September 30, 2008, approximately 67% of delivered electricity sales were to Delaware customers and approximately 33% 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.

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 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

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from period to period are changes in the number of customers and changes in the approved distribution charge per customer.

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 (FERC) under PUHCA 2005.

Impact of the Current Capital and Credit Market Disruptions

Liquidity Requirements

To address the challenges posed by the current capital and credit market environment and to ensure that it will continue to have sufficient access to cash to meet its liquidity needs, DPL has identified a number of cash and liquidity conservation measures, including opportunities to defer capital expenditures due to lower than anticipated growth. Several measures to reduce expenditures have been taken. Additional measures could be undertaken if conditions warrant.

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the temporary repurchase of tax-exempt auction rate securities. Under the current capital and credit market conditions, DPL anticipates that its funding costs will be higher than its cost of capital over the last several years.

Ongoing Monitoring of Financial and Market Conditions

DPL monitors its liquidity position on a daily basis. DPL also closely monitors its credit ratings and credit outlook and computes the hypothetical effect of changes in credit ratings on its cost of capital.

Pension and Postretirement Benefit Plans

DPL participates in pension and postretirement benefit plans sponsored by PHI for employees. While the plans have not experienced any significant impact in terms of liquidity or counterparty exposure due to the disruption of the capital and credit markets, the recent stock market declines have caused a decrease in the market value of benefit plan assets over the nine months ended September 30, 2008. A negative return for the entire year will not have an impact on DPL’s results of operations for 2008; however, such a reduction in benefit plan assets is likely to result in increased pension and postretirement benefit costs in future years.

RESULTS OF OPERATIONS

Electric Operating Revenue

		2008		2007	Change
Regulated T&D Electric Revenue	$	266.2	$	252.2	$	14.0
Default Supply Revenue		649.7		662.0		(12.3)
Other Electric Revenue		15.9		15.6		.3
Total Electric Operating Revenue	$	931.8	$	929.8	$	2.0

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.

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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 include 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	$	122.5	$	126.2	$	(3.7)
Commercial		68.9		68.1		.8
Industrial		9.1		9.1		-
Other		65.7		48.8		16.9
Total Regulated T&D Electric Revenue	$	266.2	$	252.2	$	14.0

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	3,881	4,159		(278)
Commercial	4,021	4,173		(152)
Industrial	2,006	2,133		(127)
Other	37	38		(1)
Total Regulated T&D Electric Sales	9,945	10,503		(558)

Regulated T&D Electric Customers (in thousands)	2008	2007	Change
Residential	437	455		(18)
Commercial	58	61		(3)
Industrial	1	1		-
Other	1	1		-
Total Regulated T&D Electric Customers	497	518		(21)

Due to the sale of DPL’s Virginia retail electric distribution business in January 2008, the Regulated T&D Electric Customer amounts listed above include a decrease of approximately 19,000 residential customers and 3,000 commercial customers.

Regulated T&D Electric Revenue increased by $14.0 million primarily due to the following: (i) $11.9 million increase due to a distribution rate change under the 2007 Maryland Rate Order that became effective in June 2007, including a positive $6.1 million Revenue Decoupling Adjustment, (ii) $10.5 million increase in transmission service revenues primarily due to changes in FERC formula rates in June 2008 and 2007, (iii) $4.8 million increase due to differences in consumption among the various customer rate classes, partially offset by (iv) $9.3 million decrease due to the sale of the Virginia retail electric distribution business in

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January 2008 and (v) $3.9 million decrease due to lower weather-related sales (a 5% decrease in Heating Degree Days and 18% decrease in Cooling Degree Days).

Default Electricity Supply

Default Supply Revenue		2008		2007	Change
Residential	$	423.8	$	437.4	$	(13.6)
Commercial		189.2		186.3		2.9
Industrial		29.3		31.7		(2.4)
Other		7.4		6.6		.8
Total Default Supply Revenue	$	649.7	$	662.0	$	(12.3)

Default Electricity Supply Sales (GWh)	2008	2007	Change
Residential	3,784	4,108		(324)
Commercial	1,740	1,759		(19)
Industrial	286	419		(133)
Other	32	34		(2)
Total Default Electricity Supply Sales	5,842	6,320		(478)

Default Electricity Supply Customers (in thousands)	2008	2007	Change
Residential	429	450		(21)
Commercial	49	53		(4)
Industrial	-	-		-
Other	1	1		-
Total Default Electricity Supply Customers	479	504		(25)

The change in the number of Default Electricity Supply customers was primarily due to the sale of DPL’s Virginia retail electric distribution business in January 2008, in connection with which the purchaser assumed the associated Default Supply obligations. This 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 $12.3 million primarily due to the following: (i) $24.2 million decrease due to the sale of the Virginia retail electric distribution business, (ii) $12.5 million decrease due to lower weather-related sales (a 5% decrease in Heating Degree Days and 18% decrease in Cooling Degree Days), (iii) $8.1 million decrease primarily due to differences in consumption among the various customer rate classes partially offset by (iv) $23.9 million increase in market-based Default Electricity Supply rates, and (v) $7.7 million increase primarily due to existing commercial customers electing to purchase a decreased amount of electricity from competitive suppliers.

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.

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	2008	2007
Sales to Delaware customers	56%	55%
Sales to Maryland customers	65%	68%
Sales to Virginia customers	-	92%

Natural Gas Operating Revenue

		2008		2007	Change
Regulated Gas Revenue	$	146.3	$	161.4	$	(15.1)
Other Gas Revenue		105.4		59.8		45.6
Total Natural Gas Operating Revenue	$	251.7	$	221.2	$	30.5

The table above shows the amounts of Natural Gas Operating Revenue from sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated Gas Revenue includes the revenue DPL receives for on-system natural gas delivered sales and the transportation of natural gas for customers. Other Gas Revenue includes off-system natural gas sales and the release of excess system capacity.

Regulated Gas Revenue		2008		2007	Change
Residential	$	86.1	$	94.6	$	(8.5)
Commercial		49.8		55.7		(5.9)
Industrial		4.7		6.7		(2.0)
Transportation and Other		5.7		4.4		1.3
Total Regulated Gas Revenue	$	146.3	$	161.4	$	(15.1)

Regulated Gas Sales (billion cubic feet)	2008	2007	Change
Residential	5.2	5.6		(.4)
Commercial	3.3	3.6		(.3)
Industrial	.4	.6		(.2)
Transportation and Other	5.3	4.9		.4
Total Regulated Gas Sales	14.2	14.7		(.5)

Regulated Gas Customers (in thousands)	2008	2007	Change
Residential	112	112		-
Commercial	10	9		1
Industrial	-	-		-
Transportation and Other	-	-		-
Total Regulated Gas Customers	122	121		1

Regulated Gas Revenue

Regulated Gas Revenue decreased by $15.1 million primarily due to (i) $7.3 million decrease due to Gas Cost Rate changes effective April 2007 and November 2007 (offset in Gas Purchased Expense), (ii) $6.4 million decrease due to lower weather-related sales (a 9% decrease

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in Heating Degree Days), (iii) $3.9 million decrease due to differences in consumption among the various customer rate classes, partially offset by (iv) $2.4 million increase due to a distribution base rate change effective in April 2007.

Other Gas Revenue

Other Gas Revenue, which is substantially offset in Gas Purchased expense, increased by $45.6 million primarily due to higher off-system sales of which (i) $32.4 million was attributable to an increase in market prices, and (ii) $13.8 million was attributable to an increase in demand from electric generators and gas marketers that DPL was able to fulfill due to available pipeline capacity. Higher available capacity resulted from lower demand for natural gas from regulated customers caused by warmer weather than 2007.

Operating Expenses

Fuel and Purchased Energy

Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply sales, decreased by $27.4 million to $629.2 million in 2008 from $656.6 million in 2007. The decrease was primarily due to (i) $35.7 million decrease due to the sale of the Virginia retail electric distribution business including Default Supply obligations in January 2008, (ii) $12.9 million decrease due to lower weather-related sales, (iii) $4.4 million decrease due to differences in consumption among various customer rate classes, partially offset by (iv) $19.6 million increase in average energy costs, the result of new Default Electricity Supply contracts, and (v) $6.0 million increase due to a higher rate of recovery of electricity supply costs resulting in a change in the Default Electricity Supply deferral balance. Fuel and Purchased Energy expense is substantially offset in Default Supply Revenue.

Gas Purchased

Total Gas Purchased, which is primarily offset in Regulated Gas Revenue and Other Gas Revenue, increased by $28.9 million to $199.9 million in 2008 from $171.0 million in 2007. The increase is primarily due to (i) $43.3 million increase in purchases for off-system sales, partially offset by (ii) $11.5 million decrease from the settlement of financial hedges (entered into as part of DPL’s regulated natural gas hedge program), and (iii) $8.5 million decrease due to a lower rate of recovery of natural gas supply costs resulting in a change in the Deferred Gas Fuel balance.

Other Operation and Maintenance

Other Operation and Maintenance increased by $22.0 million to $173.4 million in 2008 from $151.4 million in 2007. The increase was primarily due to the following: (i) $10.6 million increase in costs associated with Default Electricity Supply primarily due to a higher rate of recovery of bad debt expenses (substantially offset in Default Supply Revenue) as further discussed below, (ii) $3.0 million increase in preventative maintenance and system operation costs, (iii) $2.0 million increase due to higher bad debt expense, (iv) $1.6 million increase in expenses related to Blueprint for the Future and Mid-Atlantic Power Pathway projects, and (v) $1.1 million increase in employee-related costs, primarily due to the recording of additional stock-based compensation expense as further discussed below.

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In the third quarter of 2008, DPL recorded an adjustment to correct errors in Other Operation and Maintenance expenses for prior periods dating back to May 2006 where late payment fees were incorrectly recognized. This adjustment resulted in an increase in Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $2.8 million. In the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the Long-Term Incentive Plan which resulted in an understatement of DPL’s stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in DPL’s Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $1.8 million. These adjustments are not considered material either individually or in the aggregate.

Gain on Sale of Assets

Gain on Sale of Assets increased by $2.1 million to $3.1 million in 2008 from $1.0 million in 2007. The increase was primarily due to a $3.1 million gain on the sale of the Virginia retail electric distribution business on January 2, 2008.

Other Income (Expense)

Other Expenses (which are net of Other Income) decreased by $6.2 million to a net expense of $23.6 million in 2008 from a net expense of $29.8 million in 2007. The decrease was primarily due to a decrease in interest expense on short and long-term debt.

Income Tax Expense

During the second quarter 2008, DPL reached a tentative settlement with the Internal Revenue Service concerning the treatment of mixed service costs for income tax purposes during the period 2001 to 2004. On the basis of the tentative settlement, DPL updated its estimated liability related to mixed service costs and as a result, recorded a net reduction in its liability for unrecognized tax benefits of $.8 million and recognized after-tax interest income of $2.3 million in the second quarter of 2008. See “Commitments and Contingencies — Regulatory and Other Matters — IRS Mixed Service Cost Issue” in Note (10).

Capital Requirements

Capital Expenditures

DPL’s capital expenditures for the nine months ended September 30, 2008, totaled $108.5 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

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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. The MAPP Project will primarily be located in the Potomac Electric Power Company and DPL service territory. 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 the Chesapeake Bay, at an estimated cost of $400 million. These enhancements have been recommended to PJM, and if approved, will increase DPL’s projected costs associated with the MAPP Project.

As further discussed in Note (7) “Debt” to the DPL financial statements, PHI, Potomac Electric Power Company (Pepco), DPL and Atlantic City Electric Company (ACE) maintain a credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under the facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI's credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million.

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:

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

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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 influence DPL’s business and profitability;

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

Interest rate fluctuations and credit and capital market conditions; and

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

Any forward-looking statements speak only as to the date of this Quarterly Report and DPL undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of 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 1.1 million.

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

DISCONTINUED OPERATIONS

In February 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 and nine months ended September 30, 2007.

The following table summarizes discontinued operations information for the three and nine months ended September 30, 2007:

	For the Three Months Ended September 30, 2007		For the Nine Months Ended September 30, 2007
	(Millions of dollars)

Operating Revenue	$	-	$	9.7

Income Before Income Tax Expense	$	-	$	.2

Net Income	$	-	$	.1

Impact of the Current Capital and Credit Market Disruptions

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however, could have a negative effect on ACE’s financial condition, results of operations and cash flows.

Liquidity Requirements

Due to the capital and credit market disruptions, the market for commercial paper in September and October 2008 has been severely restricted for most companies. As a result, ACE has not been able to issue commercial paper on a day-to-day basis either in amounts or with maturities that it typically has required for cash management purposes. Given its restricted access to the commercial paper market and the uncertainty in the credit markets generally, in September 2008, ACE borrowed $135 million under the credit facility to create a cash reserve for future short-term operating needs.

To address the challenges posed by the current capital and credit market environment and to ensure that it will continue to have sufficient access to cash to meet its liquidity needs, ACE has identified a number of cash and liquidity conservation measures, including opportunities to defer capital expenditures due to lower than anticipated growth. Several measures to reduce expenditures have been taken. Additional measures could be undertaken if conditions warrant.

Due to the financial market conditions, which have caused uncertainty of short-term funding, ACE has obtained authority from the New Jersey Board of Public Utilities to issue up to $250 million in long-term debt securities no later than December 31, 2008. The proceeds can be used to refund short-term debt incurred to finance utility construction and operations on a temporary basis and incurred to fund the temporary repurchase of tax-exempt auction rate securities. Under the current capital and credit market conditions, ACE anticipates that its funding costs will be higher than its cost of capital over the last several years.

Ongoing Monitoring of Financial and Market Conditions

ACE monitors its liquidity position on a daily basis. ACE also closely monitors its credit ratings and credit outlook and computes the hypothetical effect of changes in credit ratings on its cost of capital.

Pension and Postretirement Benefit Plans

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months ended September 30, 2008. A negative return for the entire year will not have an impact on ACE’s results of operations for 2008; however, such a reduction in benefit plan assets is likely to result in increased pension and postretirement benefit costs in future years.

RESULTS OF OPERATIONS

Operating Revenue

	2008		2007		Change
Regulated T&D Electric Revenue	$	271.8	$	248.8	$	23.0
Default Supply Revenue		1,006.3		919.8		86.5
Other Electric Revenue		11.1		12.6		(1.5)
Total Operating Revenue	$	1,289.2	$	1,181.2	$	108.0

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. Default Supply Revenue also includes revenue from transition bond charges and other restructuring related revenues.

In response to an order issued by the New Jersey Board of Public Utilities 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 as part of Deferred Electric Service costs pending an adjustment of retail rates in a future proceeding. As a consequence of the order, 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,

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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.

Regulated T&D Electric

Regulated T&D Electric Revenue		2008		2007	Change
Residential	$	123.7	$	117.3	$	6.4
Commercial		82.9		75.8		7.1
Industrial		12.0		10.2		1.8
Other		53.2		45.5		7.7
Total Regulated T&D Electric Revenue	$	271.8	$	248.8	$	23.0

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2008	2007	Change
Residential	3,452	3,492		(40)
Commercial	3,464	3,424		40
Industrial	851	861		(10)
Other	34	33		1
Total Regulated T&D Electric Sales	7,801	7,810		(9)

Regulated T&D Electric Customers (in thousands)	2008	2007	Change
Residential	480	478		2
Commercial	64	63		1
Industrial	1	1		-
Other	1	1		-
Total Regulated T&D Electric Customers	546	543		3

Regulated T&D Electric Revenue increased by $23.0 million primarily due to the following: (i) $14.8 million increase due to a distribution rate change as part of a higher New Jersey Societal Benefit Charge that became effective in June 2008 (offset in Deferred Electric Service Costs), and (ii) $7.6 million increase in transmission service revenue primarily due to changes in the FERC formula rate in June 2008 and 2007.

Default Electricity Supply

Default Supply Revenue		2008		2007	Change
Residential	$	421.5	$	401.3	$	20.2
Commercial		295.8		286.2		9.6
Industrial		32.6		37.9		(5.3)
Other		256.4		194.4		62.0
Total Default Supply Revenue	$	1,006.3	$	919.8	$	86.5

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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 Regional Transmission Organization (PJM RTO) market.

Default Electricity Supply Sales (GWh)	2008	2007	Change
Residential	3,452	3,492		(40)
Commercial	2,461	2,487		(26)
Industrial	217	276		(59)
Other	34	33		1
Total Default Electricity Supply Sales	6,164	6,288		(124)

Default Electricity Supply Customers (in thousands)	2008	2007	Change
Residential	480	478		2
Commercial	64	63		1
Industrial	1	1		-
Other	1	1		-
Total Default Electricity Supply Customers	546	543		3

Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy and Deferred Electric Service Costs, increased by $86.5 million primarily due to the following: (i) $62.8 million increase in wholesale energy revenues due to the sale in PJM RTO at higher market prices of electricity purchased from NUGs, (ii) $37.9 million increase in market-based Default Electricity Supply rates partially offset by (iii) $11.7 million decrease primarily due to existing commercial and industrial customers electing to purchase an increased amount of electricity from competitive suppliers.

For the nine months ended September 30, 2008 and 2007, the percentage of ACE’s total sales that are derived from customers receiving Default Electricity Supply are 79% and 81%, respectively.

Operating Expenses

Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply sales, increased by $97.4 million to $913.3 million in 2008 from $815.9 in 2007. The increase was primarily due to the following: (i) $113.1 million increase due to new BGS supply contracts, partially offset by (ii) $9.3 million decrease primarily due to commercial and industrial customers electing to purchase an increased amount of electricity from competitive suppliers, and (iii) $6.4 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 $20.4 million to $139.0 million in 2008 from $118.6 million in 2007. The increase was primarily due to the following: (i) $4.2 million increase in Demand Side Management program costs (offset in Deferred Electric Service Costs), (ii) $3.5 million increase in preventative maintenance and system operation costs, (iii) $3.4

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million increase primarily due to recovery of stranded costs in 2007, (iv) $3.0 million increase due to higher bad debt expenses (offset in Deferred Electric Service Costs), (v) $1.2 million increase in legal expenses, (vi) $1.1 million increase in employee-related cost, primarily due to the recording of additional stock-based compensation expense as further discussed below, and (vii) $1.0 million increase in expenses related to Blueprint for the Future project.

In the third quarter of 2008, PHI identified an error in the accounting for certain of its restricted stock awards granted under the Long-Term Incentive Plan which resulted in an understatement of ACE’s stock-based compensation expense in 2006 and 2007. This error was corrected in the third quarter of 2008, resulting in an increase in ACE’s Other Operation and Maintenance expenses for the nine months ended September 30, 2008 of $1.3 million. This adjustment is not considered material.

Depreciation and Amortization

Depreciation and Amortization expenses increased by $24.3 million to $79.8 million in 2008 from $55.5 million in 2007. The increase was primarily due to higher amortization of stranded costs as the result of an October 2007 Transition Bond Charge rate increase (offset in Default Supply Revenue).

Deferred Electric Service Costs

Deferred Electric Service Costs decreased by $25.1 million to $20.0 million in 2008 from $45.1 million in 2007. The decrease was primarily due to (i) $42.8 million decrease due to a lower rate of recovery associated with deferred energy costs, partially offset by (ii) $13.1 million increase due to a higher rate of recovery of costs associated with energy and capacity purchased under the NUG contracts, and (iii) $2.5 million increase due to a higher rate of recovery associated with deferred transmission costs.

Income Tax Expense

During the second quarter 2008, ACE reached a tentative settlement with the Internal Revenue Service concerning the treatment of mixed service costs for income tax purposes during the period 2001 to 2004. On the basis of the tentative settlement, ACE updated its estimated liability related to mixed service costs and as a result, recorded a net reduction in its liability for unrecognized tax benefits of $2.1 million and recognized after-tax interest income of $2.2 million in the second quarter of 2008. See “Commitments and Contingencies — Regulatory and Other Matters — IRS Mixed Service Cost Issue” in Note (10).

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ACE

Capital Requirements

Capital Expenditures

ACE's capital expenditures for the nine months ended September 30, 2008, totaled $121.8 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

As further discussed in Note (7) “Debt” to the ACE financial statements, PHI, Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and ACE maintain a credit facility to provide for their respective short-term liquidity needs. The aggregate borrowing limit under the facility is $1.5 billion, all or any portion of which may be used to obtain loans or to issue letters of credit. PHI's credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million.

FORWARD-LOOKING STATEMENTS

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

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

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

Weather conditions;

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ACE

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;

Interest rate fluctuations and credit and capital market conditions; and

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

Any forward-looking statements speak only as to the date of this Quarterly Report and ACE undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of 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 (14) of the Consolidated Financial Statements of PHI, and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” included in PHI’s 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 “energy commodity” activities. PHI uses a value-at-risk (VaR) model to assess the market risk of its Competitive Energy segments’ energy commodity activities. PHI also uses other measures to limit and monitor risk in its commodity activities, including limits on the nominal size of positions and periodic loss limits. VaR represents the potential fair value loss on energy contracts or portfolios due to changes in market prices for a specified time period and confidence level. 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 Nine Months Ended September 30, 2008 (Millions of dollars)
	VaR for Competitive Energy Activity (a)
95% confidence level, one-day holding period, one-tailed
Period end	$	6.7
Average for the period	$	5.8
High	$	11.3
Low	$	3.5

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 in 2008, Conectiv Energy changed 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 in 2008, Conectiv Energy is including default electricity supply contracts and associated hedges in ISONE. The hedge percentages for all expected plant output and purchase commitment (based on the then current forward electricity price curve) are as follows:

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

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

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As of September 30, 2008, the electricity sold forward by Conectiv Energy as a percentage of projected plant output combined with energy purchase commitments was 87%, 83%, and 35% for the 1-12 month, 13-24 month and 25-36 month forward periods, respectively. The amount of forward sales during the 1-12 month period represents 23% of Conectiv Energy’s combined total generating capability and energy purchase commitments. The volumetric percentages for the forward periods can vary and may not represent the amount of expected value hedged.

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

Pepco Energy Services purchases electric and natural gas futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas and electricity for delivery to customers. Pepco Energy Services accounts for its futures and swap contracts as cash flow hedges of forecasted transactions. Its options contracts and certain commodity contracts that do not qualify as cash flow hedges are marked-to-market through current earnings. Its forward contracts are accounted for using standard accrual accounting since these contracts meet the requirements for normal purchase and 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)
	September 30, 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	$198.9	$1.0	$197.9	1	$44.2
Non-Investment Grade	61.8	-	61.8	1	52.4
No External Ratings	85.3	7.1	78.2
Credit reserves			1.5

(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.

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

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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 September 30, 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 September 30, 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.

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 September 30, 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.

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Changes in Internal Control Over Financial Reporting

During the three months ended September 30, 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.

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 September 30, 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 September 30, 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.

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 September 30, 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 September 30, 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.

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Part II OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Pepco Holdings

Other than ordinary routine litigation incidental to its and its subsidiaries’ business, PHI and its subsidiaries are not a party to, and its subsidiaries’ property is not subject to, any material pending legal proceedings except as described in Note (13), “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.

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, except that:

(1) The following risk factors have been revised and supersede the risk factors with the same heading in the Form 10-K:

The IRS challenge to cross-border energy sale and lease-back transactions entered into by a PHI subsidiary could result in loss of prior and future tax benefits.

PCI maintains a portfolio of eight cross-border energy lease investments, which as of September 30, 2008, had an equity value of approximately $1.3 billion and from which PHI had historically derived approximately $74 million per year in tax benefits in the form of interest and

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depreciation deductions in excess of rental income (reflecting 100% of the tax benefits). However, as of June 30, 2008, management reassessed the sustainability of PHI’s tax position and has revised its assumptions regarding the estimated timing of the tax benefits from its cross-border energy lease investments. Based on this reassessment, PHI for the quarter ended June 30, 2008, has recorded an after-tax charge to net income of $92.9 million, consisting of the following components (1) a non-cash pre-tax charge of $124.4 million ($86.0 million after tax) under FSP 13-2 to reduce the equity value of these cross-border energy lease investments, and (2) a non-cash charge of $6.9 million after-tax to reflect the anticipated additional interest expense under FIN 48 on the estimated federal and state income tax that would be payable for the period January 1, 2001 through June 30, 2008, based on the revised assumptions regarding the estimated timing of the tax benefits.

For further discussion of this matter, see “Change in Accounting Estimate,” in Note (2), “Leasing Activities” in Note (5), “Income Taxes” in Note (9) and “Commitments and Contingencies—Regulatory and Other Matters—PHI’s Cross-Border Energy Lease Investments,” in Note (13) to the consolidated financial statements of PHI set forth in item 1 of this Form 10-Q.

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

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. In June 2008, PHI received from the U.S. Office of Appeals of the IRS an offer of settlement pertaining to each of Pepco, DPL and ACE for the tax years 2001 through 2004. PHI is substantially in agreement with this proposed settlement. Based on the terms of the proposal, PHI expects the final settlement amount to be less than the $121 million previously deposited. See “Commitments and Contingencies—Regulatory and Other Matters—IRS Mixed Service Cost Issue,” in Note (13) to the consolidated financial statements of PHI set forth in Part I, Item 1 of this Form 10-Q

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

PHI, Pepco, DPL and ACE each rely on access to both short-term money markets and long-term capital markets as sources of liquidity and to satisfy their capital requirements that are not met by cash flow from their operations. Capital market disruptions, or a downgrade in their respective credit ratings, could increase the cost of borrowing or could prevent the companies from accessing one or more financial markets. Disruptions to the capital markets could include, but are not limited to:

·	recession or an economic slowdown;

·	the bankruptcy of one or more energy companies or financial institutions;

·	significant changes in energy prices;

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·	a terrorist attack or threatened attacks; or

·	a significant transmission failure.

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

(2) The following risk factors have been added to those set forth in the Form 10-K:

The operations of PHI’s Competitive Energy businesses can give rise to significant collateral requirements. The inability to fund those requirements may prevent the businesses from hedging associated price risks or may require curtailment of their operations.

A substantial portion of Pepco Energy Services’ business is the sale of electricity and natural gas to retail customers. In conducting this business Pepco Energy Services typically enters into electricity and natural gas sale contracts under which it is committed to supply the electricity or natural gas requirements of its retail customers over a specified period at agreed upon prices. To acquire this energy, Pepco Energy Services enters into wholesale purchase contracts for electricity and natural gas. These contracts typically impose collateral requirements on each party designed to protect the other party against the risk of nonperformance between the date the contract is entered into and the date the energy is paid for. The collateral required to be posted can be of varying forms, including cash, letters of credit and guarantees. When energy market prices decrease relative to the supplier contract prices, the collateral obligations of Pepco Energy Services increase. In addition, each of Conectiv Energy and Pepco Energy Services enters into contracts to buy and sell electricity, various fuels, and related products, including derivative instruments, to reduce its financial exposure to changes in the value of its assets and obligations due to energy price fluctuations. These contracts usually require the posting of collateral. Under various contracts entered into by both businesses, the required collateral is provided in the form of an investment grade guaranty issued by PHI. Under these contracts, a reduction in PHI’s credit rating can also trigger a requirement to post additional collateral. To satisfy these obligations when required, PHI and its non-utility subsidiaries rely primarily on cash balances, access to the capital markets and existing credit facilities.

Particularly in periods of energy market price volatility, the collateral obligations associated with the Competitive Energy businesses can be substantial. These collateral demands negatively affect PHI’s liquidity by requiring PHI to draw on its capacity under its credit facility and other financing sources. The inability of PHI to maintain the necessary liquidity also could have an adverse effect on PHI’s results of operations and financial condition by requiring the Competitive Energy businesses to forego new business opportunities, by requiring the businesses to curtail their hedging activity, thereby increasing their exposure to energy market price changes or by rendering them unable to meet their collateral obligations to counterparties.

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PHI and its subsidiaries have significant exposure to counterparty risk.

Both Conectiv Energy and Pepco Energy Services enter into transactions with numerous counterparties. These include both commercial transactions for the purchase and sale of electricity and natural gas and derivative and other transactions to manage the risk of commodity price fluctuations. Under these arrangements, the Competitive Energy businesses are exposed to the risk that the counterparty may fail to perform its obligation to make or take delivery under the contract, fail to make a required payment or fail to return collateral posted by the Competitive Energy businesses when no longer required. Under many of these contracts, Conectiv Energy and Pepco Energy Services are entitled to receive collateral or other types of performance assurance from the counterparty, which may be in the form of cash, letters of credit or parent guarantees, to protect against performance and credit risk. Even where collateral is provided, capital market disruptions can prevent the counterparty from meeting its collateral obligations or could degrade the value of letters of credit and guarantees as a result of the lowered rating or insolvency of the issuer or guarantor. In the event of a bankruptcy of a counterparty, bankruptcy law, in some circumstances, could require Conectiv Energy and Pepco Energy Services to surrender collateral held or payments received. In addition, Conectiv Energy and Pepco Energy Services are participants in the wholesale electric markets administered by various independent system operators (ISOs), and in particular PJM. If an ISO incurs losses due to counterparty nonperformance, those losses are allocated to and borne by all other market participants in the ISO. Such defaults could adversely affect PHI’s results of operations, liquidity or financial condition. These risks are increased during periods of significant commodity price fluctuations, tightened credit and ratings downgrades.

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, except that:

The following risk factor supersedes the risk factor with the same heading in the Form 10-K:

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

Pepco relies on access to both short-term money markets and long-term capital markets as sources of liquidity and to satisfy its capital requirements that are not met by cash flow from its operations. Capital market disruptions, or a downgrade in its credit ratings, could increase the cost of borrowing or could prevent it from accessing one or more financial markets. Disruptions to the capital markets could include, but are not limited to:

·	recession or an economic slowdown;

·	the bankruptcy of one or more energy companies or financial institutions;

·	significant changes in energy prices;

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·	a terrorist attack or threatened attacks; or

·	a significant transmission failure.

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, except that:

The following risk factor supersedes the risk factor with the same heading in the Form 10-K:

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

DPL relies on access to both short-term money markets and long-term capital markets as sources of liquidity and to satisfy its capital requirements that are not met by cash flow from its operations. Capital market disruptions, or a downgrade in its credit ratings, could increase the cost of borrowing or could prevent it from accessing one or more financial markets. Disruptions to the capital markets could include, but are not limited to:

·	recession or an economic slowdown;

·	the bankruptcy of one or more energy companies or financial institutions;

·	significant changes in energy prices;

·	a terrorist attack or threatened attacks; or

·	a significant transmission failure.

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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, except that:

The following risk factor supersedes the risk factor with the same heading in the Form 10-K:

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

ACE relies on access to both short-term money markets and long-term capital markets as sources of liquidity and to satisfy its capital requirements that are not met by cash flow from its operations. Capital market disruptions, or a downgrade in its credit ratings, could increase the cost of borrowing or could prevent it from accessing one or more financial markets. Disruptions to the capital markets could include, but are not limited to:

·	recession or an economic slowdown;

·	the bankruptcy of one or more energy companies or financial institutions;

·	significant changes in energy prices;

·	a terrorist attack or threatened attacks; or

·	a significant transmission failure.

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

Pepco Holdings

None.

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Item 3. DEFAULTS UPON SENIOR SECURITIES

Pepco Holdings

None.

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

Pepco Holdings

None.

Item 5. OTHER INFORMATION

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

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Item 6. EXHIBITS

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

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
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.

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Exhibit 12.1 Statements Re. Computation of Ratios

Pepco Holdings, Inc.

			For the Year Ended December 31,
	Nine Months Ended September 30, 2008			2007	2006		2005		2004		2003
	(Millions of dollars)

Income before extraordinary item (a)	$	397.3	$	324.1	$	245.0	$	368.5	$	257.4	$	204.9

Income tax expense (b)		160.8		187.9		161.4		255.2		167.3		62.1

Fixed charges:
Interest on long-term debt, amortization of discount, premium and expense		249.7		348.4		342.8		341.4		376.2		385.9
Other interest		18.5		25.4		18.8		20.3		20.6		21.7
Preferred dividend requirements of subsidiaries		.2		.3		1.2		2.5		2.8		13.9
Total fixed charges		268.4		374.1		362.8		364.2		399.6		421.5

Non-utility capitalized interest		(3.6)		(1.6)		(1.0)		(.5)		(.1)		(10.2)

Income before extraordinary item, income tax expense, and fixed charges	$	822.9	$	884.5	$	768.2	$	987.4	$	824.2	$	678.3

Total fixed charges, shown above		268.4		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	$	268.5	$	374.3	$	363.6	$	365.9	$	401.4	$	425.7

Ratio of earnings to fixed charges and preferred dividends		3.07		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 on January 1, 2007, amount includes interest on tax positions.

212

Exhibit 12.2 Statements Re. Computation of Ratios

Potomac Electric Power Company

			For the Year Ended December 31,
	Nine Months Ended September 30, 2008			2007	2006		2005		2004		2003
	(Millions of dollars)

Net income	$	92.1	$	125.1	$	85.4	$	165.0	$	96.5	$	103.2

Income tax expense (a)		59.2		62.3		57.4		127.6		55.7		67.3

Fixed charges:
Interest on long-term debt, amortization of discount, premium and expense		71.2		86.5		77.1		82.8		82.5		83.8
Other interest		8.5		11.6		12.9		13.6		14.3		16.2
Preferred dividend requirements of a subsidiary trust		-		-		-		-		-		4.6
Total fixed charges		79.7		98.1		90.0		96.4		96.8		104.6


Income before income tax expense, and fixed charges	$	231.0	$	285.5	$	232.8	$	389.0	$	249.0	$	275.1

Ratio of earnings to fixed charges		2.90		2.91		2.59		4.04		2.57		2.63

Total fixed charges, shown above		79.7		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	$	79.7	$	98.1	$	91.7	$	98.7	$	98.4	$	110.1

Ratio of earnings to fixed charges and preferred dividends		2.90		2.91		2.54		3.94		2.53		2.50

(a) Concurrent with the adoption of FIN 48 on January 1, 2007, amount includes interest on tax positions.

213

Exhibit 12.3 Statements Re. Computation of Ratios

Delmarva Power & Light Company

			For the Year Ended December 31,
	Nine Months Ended September 30, 2008			2007	2006		2005		2004		2003
	(Millions of dollars)

Net income	$	53.7	$	44.9	$	42.5	$	74.7	$	63.0	$	52.4

Income tax expense (a)		26.0		37.2		32.1		57.6		48.1		37.0

Fixed charges:
Interest on long-term debt, amortization of discount, premium and expense		28.3		43.8		41.3		35.3		33.0		37.2
Other interest		1.8		2.3		2.5		2.7		2.2		2.7
Preferred dividend requirements of a subsidiary trust		-		-		-		-		-		2.8
Total fixed charges		30.1		46.1		43.8		38.0		35.2		42.7

Income before income tax expense, and fixed charges	$	109.8	$	128.2	$	118.4	$	170.3	$	146.3	$	132.1

Ratio of earnings to fixed charges		3.65		2.78		2.70		4.48		4.16		3.09

Total fixed charges, shown above		30.1		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	$	30.1	$	46.1	$	45.2	$	39.8	$	36.9	$	44.4

Ratio of earnings to fixed charges and preferred dividends		3.65		2.78		2.62		4.28		3.96		2.98

(a) Concurrent with the adoption of FIN 48 on January 1, 2007, amount includes interest on tax positions.

214

Exhibit 12.4 Statements Re. Computation of Ratios

Atlantic City Electric Company

			For the Year Ended December 31,
	Nine Months Ended September 30, 2008			2007	2006		2005		2004		2003
	(Millions of dollars)

Income from continuing operations	$	52.8	$	60.0	$	60.1	$	51.1	$	58.8	$	31.6

Income tax (benefit) expense (a)		24.2		40.9		33.0		41.2		40.7		20.7

Fixed charges:
Interest on long-term debt, amortization of discount, premium and expense		45.8		66.0		64.9		60.1		62.2		63.7
Other interest		2.3		3.3		3.2		3.7		3.4		2.6
Preferred dividend requirements of subsidiary trusts		-		-		-		-		-		1.8
Total fixed charges		48.1		69.3		68.1		63.8		65.6		68.1

Income before extraordinary item, income tax expense, and fixed charges	$	125.1	$	170.2	$	161.2	$	156.1	$	165.1	$	120.4

Ratio of earnings to fixed charges		2.60		2.46		2.37		2.45		2.52		1.77

Total fixed charges, shown above		48.1		69.3		68.1		63.8		65.6		68.1

Preferred dividend requirements adjusted to a pre-tax amount		.3		.5		.5		.5		.5		.5

Total fixed charges and preferred dividends	$	48.4	$	69.8	$	68.6	$	64.3	$	66.1	$	68.6

Ratio of earnings to fixed charges and preferred dividends		2.58		2.44		2.35		2.43		2.50		1.76

(a) Concurrent with the adoption of FIN 48 on January 1, 2007, amount includes interest on tax positions.

215

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;

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:

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;

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;

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

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):

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

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: November 3, 2008

/s/ D. R. WRAASE

Dennis R. Wraase

Chairman of the Board and

Chief Executive Officer

216

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;

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):

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: November 3, 2008

/s/ P. H. BARRY

Paul H. Barry

Senior Vice President and

Chief Financial Officer

217

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;

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:

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):

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: November 3, 2008

/s/ J. M. RIGBY

Joseph M. Rigby

President and Chief Executive Officer

218

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;

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:

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):

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: November 3, 2008

/s/ P. H. BARRY

Paul H. Barry

Senior Vice President and

Chief Financial Officer

219

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;

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:

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):

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: November 3, 2008

/s/ J. M. RIGBY

Joseph M. Rigby

President and Chief Executive Officer

220

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;

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:

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):

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: November 3, 2008

/s/ P. H. BARRY

Paul H. Barry

Senior Vice President and

Chief Financial Officer

221

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;

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:

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):

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: November 3, 2008

/s/ J. M. RIGBY

Joseph M. Rigby

President and Chief Executive Officer

222

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;

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:

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):

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: November 3, 2008

/s/ P. H. BARRY

Paul H. Barry

Chief Financial Officer

223

Exhibit 32.1

Certificate of Chief Executive Officer and Chief Financial Officer

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 September 30, 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.

Date: November 3, 2008	/s/ D. R. WRAASE Dennis R. Wraase Chairman of the Board and Chief Executive Officer

Date: November 3, 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.

224

Exhibit 32.2

Certificate of Chief Executive Officer and Chief Financial Officer

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 September 30, 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.

Date: November 3, 2008	/s/ J. M. RIGBY Joseph M. Rigby President and Chief Executive Officer

Date: November 3, 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.

225

Exhibit 32.3

Certificate of Chief Executive Officer and Chief Financial Officer

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 September 30, 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.

Date: November 3, 2008	/s/ J. M. RIGBY Joseph M. Rigby President and Chief Executive Officer

Date: November 3, 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.

226

Exhibit 32.4

Certificate of Chief Executive Officer and Chief Financial Officer

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 September 30, 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.

Date: November 3, 2008	/s/ J. M. RIGBY Joseph M. Rigby President and Chief Executive Officer

Date: November 3, 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.

227

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) (Registrant)
November 3, 2008	By /s/ P. H. BARRY Paul H. Barry Senior Vice President and Chief Financial Officer, PHI, Pepco and DPL Chief Financial Officer, ACE

228

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

229