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, 2007
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, 2007
Pepco Holdings	193,768,141 ($.01 par value)
Pepco	100 ($.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	104
Item 3.	-	Quantitative and Qualitative Disclosures    About Market Risk	184
Item 4.	-	Controls and Procedures	187
Item 4T.	-	Controls and Procedures	187
PART II	OTHER INFORMATION		189
Item 1.	-	Legal Proceedings	189
Item 1A.	-	Risk Factors	189
Item 2.	-	Unregistered Sales of Equity Securities and Use of Proceeds	190
Item 3.	-	Defaults Upon Senior Securities	190
Item 4.	-	Submission of Matters to a Vote of Security Holders	191
Item 5.	-	Other Information	191
Item 6.	-	Exhibits	191
Signatures			209

TABLE OF CONTENTS - EXHIBITS
Exh. No.	Registrant(s)	Description of Exhibit	Page
12.1	PHI	Statements Re: Computation of Ratios	193
12.2	Pepco	Statements Re: Computation of Ratios	194
12.3	DPL	Statements Re: Computation of Ratios	195
12.4	ACE	Statements Re: Computation of Ratios	196
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	197
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	198
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	199
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	200
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	201
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	202
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	203
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	204
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	205
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	206
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	207
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	208

	GLOSSARY OF TERMS
Term	Definition
A&N	A&N Electric Cooperative, which has entered into an agreement with DPL to purchase DPL's business of distributing retail electric services to customers located on the Eastern Shore of Virginia
ABO	Accumulated benefit obligation
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
ACO	Administrative Consent Order
ADFIT	Accumulated deferred Federal income taxes
ADITC	Accumulated deferred investment tax credits
Ancillary services	Generally, electricity generation reserves and reliability services
APCA	New Jersey Air Pollution Control Act
APIC	Additional paid-in capital
Appellate Division	Appellate Division of the Superior Court of New Jersey
Asset Purchase and   Sale Agreement	Asset Purchase and Sale Agreement, dated as of June 7, 2000 and subsequently amended, between Pepco and Mirant (formerly Southern Energy, Inc.) relating to the sale of Pepco's generation assets
Bankruptcy Court	Bankruptcy Court for the Northern District of Texas
Bankruptcy Funds	$13.25 million in funds from the Bankruptcy Settlement
Bankruptcy Settlement	The bankruptcy settlement among the parties concerning the environmental proceedings at the Metal Bank/Cottman Avenue environmental remediation site
Bcf	Billion cubic feet
BGS	Basic Generation Service (the supply of electricity by ACE to retail customers in New Jersey who have not elected to purchase electricity from a competitive supplier)
BSA	Bill stabilization adjustment mechanism, which "decouples" revenue from unit sales consumption and ties the growth in revenues to the growth in the number of customers
Citgo	Citgo Asphalt Refining Co.
Competitive Energy   business	Consists of the business operations of Conectiv Energy and Pepco Energy Services
Conectiv	A wholly owned subsidiary of PHI, which is a PUHCA 2005 holding company. Conectiv also is the parent of DPL and ACE
Conectiv Energy	Conectiv Energy Holding Company and its subsidiaries
Conectiv Group	Conectiv and certain of its subsidiaries, involved in a like-kind exchange transaction
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 within PHI's service territories at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as Default Service, SOS, BGS, or formerly POLR service
Default Service	The supply of electricity by DPL in Virginia to retail customers who have not elected to purchase electricity from a competitive supplier
Default Supply Revenue	Revenue received for Default Electricity Supply
Delaware District Court	U.S. District Court for the District of Delaware
District Court	U.S. District Court for the Northern District of Texas

i

Term	Definition
DPL	Delmarva Power & Light Company
DPSC	Delaware Public Service Commission
EDECA	New Jersey Electric Discount and Energy Competition Act
EDIT	Excess Deferred Income Taxes
EITF	Emerging Issues Task Force
EPA	U.S. Environmental Protection Agency
EPS	Earnings per share
ERISA	Employment Retirement Income Security Act of 1974
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fifth Circuit	U.S. Court of Appeals for the Fifth Circuit
FIN	FASB Interpretation Number
First Order	Administrative Order and Notice of Civil Administrative Penalty Assessment issued by NJDEP on April 3, 2007
FSP	FASB Staff Position
FSP AUG AIR-1	FSP American Institute of Certified Public Accountants Industry Audit Guide, Audits of Airlines--"Accounting for Planned Major Maintenance Activities"
FTB	FASB Technical Bulletin
GAAP	Accounting principles generally accepted in the United States of America
GCR	Gas Cost Rate
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
LEAC Liability	ACE's $59.3 million deferred energy cost liability existing as of July 31, 1999, related to ACE's Levelized Energy Adjustment Clause and ACE's Demand Side Management Programs
MAPP Project	Mid-Atlantic Power Pathway Project
MDE	Maryland Department of the Environment
MGP	Manufactured gas plant
Mirant	Mirant Corporation and its predecessors and its subsidiaries
MOA	Memorandum of Agreement
MPSC	Maryland Public Service Commission
NFA	No Further Action Letter issued by NJDEP
NGC	Non Utility Generation Charge in New Jersey
NJBPU	New Jersey Board of Public Utilities
NJDEP	New Jersey Department of Environmental Protection
NOPR	Notice of Proposed Rulemaking by the IRS
Normalization provisions	Sections of the Internal Revenue Code and related regulations that dictate how excess deferred income taxes resulting from the corporate income tax rate reduction enacted by the Tax Reform Act of 1986 and accumulated deferred investment tax credits should be treated for ratemaking purposes
Notice	Notice 2005-13 issued by the Treasury Department and IRS on February 11, 2005
NOVAC	Northern Virginia Electric Cooperative

ii

Term	Definition
NUGs	Non-utility generation contracts between ACE and unaffiliated third parties
NYDEC	New York Department of Environmental Conservation
OAL	New Jersey Office of Administrative Law
OCI	Other Comprehensive Income
ODEC	Old Dominion Electric Cooperative, which has entered into an agreement with DPL to purchase certain assets principally related to DPL's provision of electric transmission services located on the Eastern Shore of Virginia
Panda	Panda-Brandywine, L.P.
Panda PPA	PPA between Pepco and Panda
PBO	Projected benefit obligation
PCI	Potomac Capital Investment Corporation and its subsidiaries
Pepco	Potomac Electric Power Company
Pepco Energy Services	Pepco Energy Services, Inc. and its subsidiaries
Pepco Holdings or PHI	Pepco Holdings, Inc.
PHI Parties	The PHI Retirement Plan, PHI and Conectiv
PJM	PJM Interconnection, LLC
PLR	Private letter ruling from the IRS
POLR	Provider of Last Resort service (the supply of electricity by DPL before May 1, 2006 to retail customers in Delaware who have not elected to purchase electricity from a competitive supplier)
Power Delivery	PHI's Power Delivery Business
PPA	Power Purchase Agreement
PPA-Related   Obligations	Mirant's obligations to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the FirstEnergy and the Panda PPAs
PRP	Potentially responsible party
PUHCA 1935	Public Utility Holding Company of 1935, which was repealed effective February 8, 2006
PUHCA 2005	Public Utility Holding Company Act of 2005, which became effective February 8, 2006
RAR	IRS Revenue Agent's Report
RC Cape May	RC Cape May Holdings, LLC, an affiliate of Rockland Capital Energy Investments, and the buyer of the B.L. England generating facility
Recoverable stranded costs	The portion of stranded costs that is recoverable from ratepayers as approved by regulatory authorities
Reorganization Plan	Mirant's Plan of Reorganization
RI/FS	Remedial Investigation/Feasibility Study
ROE	Return on equity
SBC	Societal Benefits Charge in New Jersey
SEC	Securities and Exchange Commission
Second Order	Administrative Order and Notice of Civil Administrative Penalty Assessment issued by NJDEP on May 23, 2007
Settlement Agreement	Amended Settlement Agreement and Release, dated as of May 30, 2006 between Pepco and Mirant
SFAS	Statement of Financial Accounting Standards
SMECO	Southern Maryland Electric Cooperative, Inc.
SMECO Agreement	Capacity purchase agreement between Pepco and SMECO

iii

Term	Definition
SMECO Settlement   Agreement	Settlement Agreement and Release entered into between Mirant and SMECO
SOS	Standard Offer Service (the supply of electricity by Pepco in the District of Columbia, by Pepco and DPL in Maryland and by DPL in Delaware on and after May 1, 2006, to retail customers who have not elected to purchase electricity from a competitive supplier)
Standard Offer Service   revenue or SOS revenue	Revenue Pepco receives for the procurement of energy by Pepco for its SOS customers
Stranded costs	Costs incurred by a utility in connection with providing service which would otherwise be unrecoverable in a competitive or restructured market. Such costs may include costs for generation assets, purchased power costs, and regulatory assets and liabilities, such as accumulated deferred income taxes.
T&D	Transmission and distribution
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	A contract for terminal services between ACE and Citgo, which was purchased by RC Cape May as part of the B.L. England sale
Utility PRPs	A group of utility PRPs including Pepco, parties to a settlement involving the environmental proceedings at the Metal Bank/Cottman Avenue site
VaR	Value at Risk
Virginia District Court	U.S. District Court for the Eastern District of Virginia
VSCC	Virginia State Corporation Commission

iv

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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	49	70	86
Consolidated Statements of Comprehensive Earnings	4	N/A	N/A	N/A
Consolidated Balance Sheets	5	50	71	87
Consolidated Statements of Cash Flows	7	52	73	89
Notes to Consolidated Financial Statements	8	53	74	90
*  Pepco and DPL have no subsidiaries and therefore their financial statements are not consolidated.
1

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2

PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EARNINGS (Unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
		2007		2006		2007		2006
		(Millions, except per share data)
Operating Revenue
Power Delivery	$	1,596.3	$	1,660.7	$	4,033.7	$	4,014.9
Competitive Energy		1,155.8		910.0		2,947.0		2,377.7
Other		18.2		19.2		52.7		65.8
Total Operating Revenue		2,770.3		2,589.9		7,033.4		6,458.4
Operating Expenses
Fuel and purchased energy		1,890.7		1,720.8		4,780.1		4,166.4
Other services cost of sales		160.5		177.0		433.2		502.1
Other operation and maintenance		214.3		200.1		632.2		614.0
Depreciation and amortization		87.6		110.4		273.4		318.7
Other taxes		100.0		95.9		271.5		259.9
Deferred electric service costs		29.1		30.7		47.2		20.5
Impairment loss		-		12.6		1.6		19.1
Effect of settlement of Mirant bankruptcy claims		(33.4)		-		(33.4)		-
Loss (gain) on sale of assets		.7		(.4)		(1.8)		(2.2)
Total Operating Expenses		2,449.5		2,347.1		6,404.0		5,898.5
Operating Income		320.8		242.8		629.4		559.9
Other Income (Expenses)
Interest and dividend income		4.9		4.3		11.7		12.0
Interest expense		(86.2)		(87.0)		(254.6)		(253.8)
Income (loss) from equity investments		3.1		(.4)		10.2		.1
Other income		5.8		9.0		21.2		41.5
Other expenses		(.5)		(2.1)		(.9)		(10.0)
Total Other Expenses		(72.9)		(76.2)		(212.4)		(210.2)
Preferred Stock Dividend Requirements of Subsidiaries		.1		.3		.3		1.0
Income Before Income Tax Expense		247.8		166.3		416.7		348.7
Income Tax Expense		80.2		62.3		140.3		136.7
Net Income		167.6		104.0		276.4		212.0
Retained Earnings at Beginning of Period		1,069.6		1,027.9		1,068.7		1,018.7
Cumulative Effect Adjustment Related to   the Implementation of FIN 48		-		-		(7.4)		-
LTIP Dividend		(.1)		-		(.3)		-
Dividends Paid on Common Stock		(50.2)		(49.7)		(150.5)		(148.5)
Retained Earnings at End of Period	$	1,186.9	$	1,082.2	$	1,186.9	$	1,082.2
Basic and Diluted Share Information
Weighted average shares outstanding		193.5		190.8		193.1		190.4
Earnings per share of common stock	$	.87	$	.54	$	1.43	$	1.11
The accompanying Notes are an integral part of these Consolidated Financial Statements.
3

PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS (Unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
		2007		2006		2007		2006
		(Millions of dollars)
Net income	$	167.6	$	104.0	$	276.4	$	212.0
Other comprehensive earnings (losses)
Unrealized gains (losses) on commodity     derivatives designated as cash flow hedges:
Unrealized holding losses arising during period		(79.9)		(26.7)		(59.6)		(143.9)
Less: reclassification adjustment for                 (losses) gains included in net earnings		(50.7)		(22.9)		(63.2)		4.4
Net unrealized (losses) gains on commodity derivatives		(29.2)		(3.8)		3.6		(148.3)
Realized gains on Treasury lock transactions		1.8		2.9		8.0		8.8
Amortization of gains and losses for prior service costs		(.6)		-		(.6)		-
Other comprehensive (losses) earnings, before taxes		(28.0)		(.9)		11.0		(139.5)
Income tax (benefit) expense		(9.7)		1.4		5.3		(54.3)
Other comprehensive (losses) earnings, net of income taxes		(18.3)		(2.3)		5.7		(85.2)
Comprehensive earnings	$	149.3	$	101.7	$	282.1	$	126.8
The accompanying Notes are an integral part of these Consolidated Financial Statements.
4

PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
ASSETS		September 30, 2007		December 31, 2006
	(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$	26.0	$	48.8
Restricted cash			15.1		12.0
Accounts receivable, less allowance for     uncollectible accounts of $29.4 million     and $35.8 million, respectively			1,413.5		1,253.5
Fuel, materials and supplies - at average cost			294.9		288.8
Unrealized gains - derivative contracts			18.0		72.7
Prepayments of income taxes			221.3		228.4
Prepaid expenses and other			92.8		77.2
Total Current Assets			2,081.6		1,981.4
INVESTMENTS AND OTHER ASSETS
Goodwill			1,407.9		1,409.2
Regulatory assets			1,524.7		1,570.8
Investment in finance leases held in trust			1,369.3		1,321.8
Income taxes receivable			196.2		-
Restricted cash			426.2		17.5
Other			355.0		366.2
Total Investments and Other Assets			5,279.3		4,685.5
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			12,087.0		11,819.7
Accumulated depreciation			(4,390.2)		(4,243.1)
Net Property, Plant and Equipment			7,696.8		7,576.6
TOTAL ASSETS		$	15,057.7	$	14,243.5
The accompanying Notes are an integral part of these Consolidated Financial Statements.
5

PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY		September 30, 2007		December 31, 2006
	(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt		$	596.2	$	349.6
Current maturities of long-term debt			359.0		857.5
Accounts payable and accrued liabilities			780.7		700.7
Capital lease obligations due within one year			5.7		5.5
Taxes accrued			68.2		99.9
Interest accrued			73.3		80.1
Liabilities and accrued interest related to uncertain tax positions			128.5		-
Other			316.4		440.7
Total Current Liabilities			2,328.0		2,534.0
DEFERRED CREDITS
Regulatory liabilities			1,218.9		842.7
Deferred income taxes			2,098.9		2,084.0
Investment tax credits			36.8		46.1
Pension benefit obligation			83.6		78.3
Other postretirement benefit obligations			412.2		405.0
Income taxes payable			161.9		-
Other			292.0		249.4
Total Deferred Credits			4,304.3		3,705.5
LONG-TERM LIABILITIES
Long-term debt			4,071.6		3,768.6
Transition Bonds issued by ACE Funding			442.8		464.4
Long-term project funding			21.3		23.3
Capital lease obligations			108.2		111.1
Total Long-Term Liabilities			4,643.9		4,367.4
COMMITMENTS AND CONTINGENCIES (NOTE 4)
MINORITY INTEREST			6.2		24.4
SHAREHOLDERS' EQUITY
Common stock, $.01 par value, authorized     400,000,000 shares, 193,768,141 shares and     191,932,445 shares outstanding, respectively			1.9		1.9
Premium on stock and other capital contributions			2,684.2		2,645.0
Accumulated other comprehensive loss			(97.7)		(103.4)
Retained earnings			1,186.9		1,068.7
Total Shareholders' Equity			3,775.3		3,612.2
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		$	15,057.7	$	14,243.5
The accompanying Notes are an integral part of these Consolidated Financial Statements.
6

PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
		Nine Months Ended September 30,
			2007		2006
	(Millions of dollars)
OPERATING ACTIVITIES
Net income		$	276.4	$	212.0
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization			273.4		318.7
Effect of settlement of Mirant bankruptcy claims			(33.4)		-
Gain on sale of assets			(1.8)		(2.2)
Gain on sale of other investment			(.7)		(13.7)
Impairment loss			1.6		19.1
Rents received from leveraged leases under income earned			(57.5)		(66.9)
Proceeds from settlement of Mirant bankruptcy claims			507.2		70.0
Reimbursements to Mirant			(108.3)		-
Changes in restricted cash related to Mirant settlement			(416.7)		-
Deferred income taxes			112.9		112.4
Changes in:
Accounts receivable			(185.3)		52.9
Regulatory assets and liabilities			17.9		(6.9)
Accounts payable and accrued liabilities			62.9		(339.7)
Interest and taxes accrued			(22.2)		(325.0)
Other changes in working capital			12.0		(15.8)
Net other operating			24.1		(34.3)
Net Cash From (Used By) Operating Activities			462.5		(19.4)
INVESTING ACTIVITIES
Net investment in property, plant and equipment			(422.7)		(356.3)
Proceeds from settlement of Mirant bankruptcy claims representing   reimbursement for investment in property, plant and equipment			15.0		-
Proceeds from sale of assets			10.6		180.6
Proceeds from the sale of other investments			1.2		16.0
Changes in restricted cash			4.9		5.9
Net other investing activities			(.8)		7.3
Net Cash Used By Investing Activities			(391.8)		(146.5)
FINANCING ACTIVITIES
Dividends paid on common stock			(150.5)		(148.5)
Dividends paid on preferred stock			(.3)		(1.0)
Common stock issued for the Dividend Reinvestment Plan			21.0		22.6
Issuance of common stock			23.9		10.0
Preferred stock redeemed			(18.2)		(21.5)
Issuances of long-term debt			452.8		217.0
Reacquisition of long-term debt			(670.8)		(502.0)
Issuances of short-term debt, net			246.6		510.9
Cost of issuances			(3.0)		(3.5)
Net other financing activities			5.0		3.6
Net Cash (Used By) From Financing Activities			(93.5)		87.6
Net Decrease in Cash and Cash Equivalents			(22.8)		(78.3)
Cash and Cash Equivalents at Beginning of Period			48.8		121.5
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	26.0	$	43.2
NONCASH ACTIVITIES
Asset retirement obligations associated with removal   costs transferred to regulatory liabilities		$	8.6	$	74.1
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash (received) paid for income taxes		$	(5.8)	$	179.7
The accompanying Notes are an integral part of these Consolidated Financial Statements.
7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PEPCO HOLDINGS, INC.

(1)  ORGANIZATION

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

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

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

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

     On February 8, 2006, the Public Utility Holding Company Act of 1935 (PUHCA 1935) was repealed and the Public Utility Holding Company Act of 2005 (PUHCA 2005) went into effect. As a result, PHI has ceased to be regulated by the Securities and Exchange Commission (SEC) as a public utility holding company and is now subject to the regulatory oversight of the Federal Energy Regulatory Commission (FERC). As permitted under FERC regulations promulgated under PUHCA 2005, PHI has given notice to FERC that it will continue, until further notice, to operate pursuant to the authority granted in the financing order issued by the SEC under PUHCA 1935, which has an authorization period ending June 30, 2008, relating to the issuance of securities and guarantees, other financing transactions and the operation of PHI's money pool.

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

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

Power Delivery

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

     PHI's Power Delivery business is conducted by its three regulated utility subsidiaries: Pepco, DPL and ACE. Each subsidiary is a regulated public utility in the jurisdictions that comprise its service territory. Pepco, DPL and ACE each owns and operates a network of wires, substations and other equipment that are classified either as transmission or distribution facilities.

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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 supplier. The regulatory term for this supply service varies by jurisdiction as follows:

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

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

Other Business Operations

     Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy sale-leaseback transactions with a book value at September 30, 2007 of approximately $1.4 billion. This activity constitutes a fourth operating segment, which is designated as "Other Non-Regulated" for financial reporting purposes. For a discussion of PHI's cross-border leasing transactions, see "Regulatory and Other Matters -- Federal Tax Treatment of Cross-border Leases."

(2)  ACCOUNTING POLICY, PRONOUNCEMENTS, AND OTHER DISCLOSURES

Financial Statement Presentation

     Pepco Holdings' unaudited consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the SEC, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements

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included in PHI's Annual Report on Form 10-K for the year ended December 31, 2006. In the opinion of PHI's management, the unaudited consolidated financial statements contain all adjustments (consisting of normal recurring accruals) necessary to present fairly Pepco Holdings' financial results for the interim periods presented herein. 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, 2007 may not be indicative of PHI's results that will be realized for the full year ending December 31, 2007, since its Power Delivery and Competitive Energy businesses are seasonal.

FIN 46R, "Consolidation of Variable Interest Entities"

     Subsidiaries of Pepco Holdings have power purchase agreements (PPAs) with a number of entities, including three contracts between unaffiliated non-utility generators (NUGs) and ACE and an agreement between Pepco and Panda-Brandywine, L.P. (Panda) entered into in 1991, pursuant to which Pepco is obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (Panda PPA). Due to a variable element in the pricing structure of the NUGs and the Panda PPA, the Pepco Holdings' subsidiaries potentially assume the variability in the operations of the plants related to these PPAs and therefore have a variable interest in the counterparties to these PPAs. In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R (revised December 2003), entitled "Consolidation of Variable Interest Entities" (FIN 46R), Pepco Holdings continued, during the third quarter of 2007, to conduct exhaustive efforts to obtain inform ation from these four entities, but was unable to obtain sufficient information to conduct the analysis required under FIN 46R to determine whether these four entities were variable interest entities or if Pepco Holdings' subsidiaries were the primary beneficiary. As a result, Pepco Holdings has applied the scope exemption from the application of FIN 46R for enterprises that have conducted exhaustive efforts to obtain the necessary information, but have not been able to obtain such information.

     Net purchase activities with the counterparties to the NUGs and the Panda PPA for the three months ended September 30, 2007 and 2006 were approximately $112 million and $109 million, respectively, of which approximately $102 million and $99 million, respectively, were related to power purchases under the NUGs and the Panda PPA. Net purchase activities with the counterparties to the NUGs and the Panda PPA for the nine months ended September 30, 2007 and 2006 were approximately $314 million and $310 million, respectively, of which approximately $289 million and $281 million, respectively, were related to power purchases under the NUGs and the Panda PPA. For further information regarding the funding of power purchases under the Panda PPA, see Note (4), Commitments and Contingencies, under "Final Resolution of Mirant Bankruptcy Matter." Pepco Holdings does not have loss exposure under the NUGs because cost recovery will be achieved from ACE's customers through regulated rates.

     In April 2006, the FASB issued FASB Staff Position (FSP) 46(R)-6, "Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)" (FSP FIN 46(R)-6), which provides guidance on how to determine the variability to be considered in applying FIN 46(R). Pepco Holdings started applying the guidance in FSP FIN 46(R)-6 to new and modified arrangements effective July 1, 2006.

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FIN 48, "Accounting for Uncertainty in Income Taxes"

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

     On May 2, 2007, the FASB issued FSP FIN 48-1, "Definition of Settlement in FASB Interpretation No. 48" (FIN 48-1), which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. PHI applied the guidance of FIN 48-1 with its adoption of FIN 48 on January 1, 2007.

     PHI adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, PHI originally recorded a $1.4 million increase in retained earnings, representing the cumulative effect of the change in accounting principle. This adjustment was reflected for the first time in PHI's Form 10-Q for the quarter ended March 31, 2007. Unrecognized tax benefits represent those tax benefits related to tax positions that have been taken or are expected to be taken in tax returns, including refund claims, that are not recognized in the financial statements because, in accordance with FIN 48, management has either measured the tax benefit at an amount less than the benefit claimed or expected to be claimed or concluded that it is not more likely than not that the tax position will be ultimately sustained. As of January 1, 2007, unrecognized tax benefits totaled $186.9 million. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. Unrecognized tax benefits at January 1, 2007, included $35.3 million that, if recognized, would lower the effective tax rate.

     During the third quarter of 2007, PHI determined that an incorrect interest rate had been applied to certain tax overpayments due to Pepco. This error affected the interest accrued upon adoption of FIN 48 at January 1, 2007 during the first and second quarters of 2007. To correct this error, the original Cumulative Effect Adjustment included in retained earnings related to the implementation of FIN 48 has been adjusted by an $8.7 million charge to reflect the accrual of interest at the proper interest rate. Further, the related interest accruals for each of the first two quarters of 2007 were overstated by $.5 million. The adjustment of $1.0 million to correct this overaccrual has been recorded in the third quarter of 2007.

     PHI recognizes interest on under/over payments of income taxes and penalties in income tax expense. As of January 1, 2007, PHI had accrued approximately $25.0 million of interest expense and penalties.

     PHI and the majority of its subsidiaries file a consolidated Federal income tax return. PHI's Federal income tax liabilities for Pepco legacy companies for all years through 2000, and for Conectiv legacy companies for all years through 1999, have been determined, subject to

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adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where PHI files state income tax returns (District of Columbia, Maryland, Delaware, New Jersey, Pennsylvania and Virginia), are the same as noted above.

     Total unrecognized tax benefits that may change over the next twelve months include the matter described in Note (4) Commitments and Contingencies under the heading "IRS Mixed Service Cost Issue."

     Included in the amount of unrecognized tax benefits at January 1, 2007 is a state of Maryland claim for refund in the amount of $31.8 million. Pepco filed an amended 2000 Maryland tax return on November 14, 2005 claiming the refund. The amended return claimed additional tax basis for purposes of computing the Maryland tax gain on the sale of Pepco's generating plants based on the tax benefit rule. This claim for refund was rejected by the state. Pepco filed an appeal by letter dated June 28, 2006. The Hearing Officer denied the appeal by a Notice of Final Determination dated February 22, 2007. Pepco petitioned Maryland Tax Court on March 22, 2007 for the refund. On August 1, 2007, Pepco entered into a settlement agreement with the Comptroller of Maryland on this matter. For further discussion, see "Maryland Income Tax Refund" below.

Components of Net Periodic Benefit Cost

     The following Pepco Holdings' information is for the three months ended September 30, 2007 and 2006.

		Pension Benefits				Other Postretirement Benefits
		2007		2006		2007		2006
	(Millions of dollars)
Service cost	$	12.7	$	10.1	$	1.8	$	2.1
Interest cost		25.4		24.2		9.2		8.7
Expected return on plan assets		(32.6)		(32.5)		(3.3)		(2.9)
Amortization of prior service cost		.2		.2		(1.1)		(1.0)
Amortization of net loss		5.4		4.4		2.8		3.6
Net periodic benefit cost	$	11.1	$	6.4	$	9.4	$	10.5

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     The following Pepco Holdings' information is for the nine months ended September 30, 2007 and 2006.

		Pension Benefits				Other Postretirement Benefits
		2007		2006		2007		2006
	(Millions of dollars)
Service cost	$	30.8	$	30.4	$	5.4	$	6.3
Interest cost		76.3		72.7		27.5		26.0
Expected return on plan assets		(97.7)		(97.5)		(10.0)		(8.7)
Amortization of prior service cost		.6		.6		(3.1)		(2.9)
Amortization of net loss		10.1		13.1		8.5		10.7
Net periodic benefit cost	$	20.1	$	19.3	$	28.3	$	31.4

     Pension

     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. The pension net periodic benefit cost for the three months ended September 30, 2006 of $6.4 million includes $3.4 million for Pepco, $1.2 million for ACE, and $(1.6) million for DPL. The pension net periodic benefit cost for the nine months ended September 30, 2006 of $19.3 million includes $10.0 million for Pepco, $3.7 million for ACE, and $(4.6) million for DPL. The remaining pension net periodic benefit cost is for other PHI subsidiaries.

     Pension Contributions

     Pepco Holdings' current funding policy with regard to its defined benefit pension plan is to maintain a funding level in excess of 100% of its accumulated benefit obligation (ABO). PHI's pension plan currently meets the minimum funding requirements of the Employment Retirement Income Security Act of 1974 (ERISA) without any additional funding. PHI may elect, however, to make a discretionary tax-deductible contribution to maintain the pension plan's assets in excess of its ABO. In 2006 and 2005, PHI made discretionary tax-deductible cash contributions to the plan of zero and $60 million, respectively. During the three and nine months ended September 30, 2007, no contributions were made to the plan. The potential discretionary funding of the pension plan in 2007 will depend on many factors, including the actual investment return earned on plan assets over the remainder of the year.

     Other Postretirement Benefits

     The other postretirement net periodic benefit cost for the three months ended 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. The other postretirement net periodic benefit cost for the three months ended September 30, 2006 of $10.5 million includes $4.7 million for Pepco, $2.4 million for ACE, and

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$1.7 million for DPL. The other postretirement net periodic benefit cost for the nine months ended September 30, 2006 of $31.4 million includes $14.1 million for Pepco, $7.0 million for ACE, and $5.1 million for DPL. The remaining other postretirement net periodic benefit cost is for other PHI subsidiaries.

Stock-Based Compensation

     No stock options were granted for the three and nine months ended September 30, 2007.

     There were no options exercised under all share-based payment arrangements for the quarter ended September 30, 2007. Cash received from options exercised under all share-based payment arrangements for the nine months ended September 30, 2007, was $13.2 million and the actual tax benefit realized for the tax deductions resulting from these options exercised totaled $1.2 million.

Calculations of Earnings Per Share of Common Stock

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

		Three Months Ended September 30,
					2007		2006
			(In millions, except per share data)
Income (Numerator):
Net Income				$	167.6	$	104.0
Add: Loss on redemption of subsidiary's preferred stock					-		-
Earnings Applicable to Common Stock				$	167.6	$	104.0
Shares (Denominator) (a):
Weighted average shares outstanding for basic computation:
Average shares outstanding					193.5		190.8
Adjustment to shares outstanding					(.2)		(.1)
Weighted Average Shares Outstanding for Computation of   Basic Earnings Per Share of Common Stock					193.3		190.7
Weighted average shares outstanding for diluted computation:
Average shares outstanding					193.5		190.8
Adjustment to shares outstanding					.3		.4
Weighted Average Shares Outstanding for Computation of   Diluted Earnings Per Share of Common Stock					193.8		191.2
Basic earnings per share of common stock				$	.87	$	.54
Diluted earnings per share of common stock				$	.87	$	.54
(a)	The number of options to purchase shares of common stock that were excluded from the calculation of diluted earnings per share (EPS) as they are considered to be anti-dilutive were zero and approximately .6 million for the three months ended September 30, 2007 and 2006, respectively.

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		Nine Months Ended September 30,
					2007		2006
			(In millions, except per share data)
Income (Numerator):
Net Income				$	276.4	$	212.0
Add: Loss on redemption of subsidiary's preferred stock					(.6)		(.8)
Earnings Applicable to Common Stock				$	275.8	$	211.2
Shares (Denominator) (a):
Weighted average shares outstanding for basic computation:
Average shares outstanding					193.1		190.4
Adjustment to shares outstanding					(.3)		(.2)
Weighted Average Shares Outstanding for Computation of   Basic Earnings Per Share of Common Stock					192.8		190.2
Weighted average shares outstanding for diluted computation:
Average shares outstanding					193.1		190.4
Adjustment to shares outstanding					.2		.3
Weighted Average Shares Outstanding for Computation of   Diluted Earnings Per Share of Common Stock					193.3		190.7
Basic earnings per share of common stock				$	1.43	$	1.11
Diluted earnings per share of common stock				$	1.43	$	1.11
(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 zero and approximately .6 million for the nine months ended September 30, 2007 and 2006, respectively.

Impairment Loss

     During the nine months ended September 30, 2007, Pepco Holdings recorded pre-tax impairment losses of $1.6 million ($1.0 million after-tax) on certain energy services business assets owned by Pepco Energy Services. None of these impairment losses were recorded in the third quarter. During the three and nine months ended September 30, 2006, Pepco Holdings recorded pre-tax impairment losses of $12.6 million ($7.9 million, after-tax) and $19.1 million ($12.1 million after-tax), respectively, on certain energy services business assets owned by Pepco Energy Services.

Sale of Interest in Cogeneration Joint Venture

     During the first quarter of 2006, Conectiv Energy recognized a $12.3 million pre-tax gain ($7.9 million after-tax) on the sale of its equity interest in a joint venture which owns a wood burning cogeneration facility in California. The pre-tax gain is included in the line item entitled "Other Income" in the accompanying consolidated statement of earnings.

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Goodwill

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

Balance,  December 31, 2006	$  1,409.2
Less:  Second quarter adjustment due to resolution of                     pre-merger tax contingencies	(1.9)
Third quarter adjustment due to correction of                    pre-merger deferred tax balances	.6
Balance,  September 30, 2007	$  1,407.9

Reconciliation of Consolidated Income Tax Expense

     A reconciliation of PHI's consolidated income tax expense is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
	Amount	Rate	Amount	Rate	Amount	Rate	Amount	Rate
	(Millions of dollars)
Income Before Income Tax Expense	$247.8		$166.3		$416.7		$348.7
Add: Preferred stock dividend           requirements of subsidiaries	.1		.3		.3		1.0
Income Before Income Tax Expense       and Preferred Dividends	$247.9		$166.6		$417.0		$349.7
Income tax at Federal statutory rate	$  86.8	35%	$  58.3	35%	$146.0	35%	$122.4	35%
Increases (decreases) resulting from:
Depreciation	1.8	1	2.1	1	6.2	1	6.1	2
Asset removal costs	(.5)	-	(.5)	-	(1.6)	-	(2.4)	(1)
Maryland State refund,        net of Federal effect	(19.5)	(8)	-	-	(19.5)	(5)	-	-
State income taxes, net of        Federal effect	10.7	4	9.2	6	16.4	4	21.8	6
Tax credits	(1.4)	(1)	(1.2)	(1)	(3.8)	(1)	(3.5)	(1)
Company dividends reinvested       in 401(k) Plan	(.5)	-	(.5)	-	(1.1)	-	(1.6)	(1)
Leveraged leases	(1.9)	(1)	(2.0)	(1)	(5.7)	(1)	(6.9)	(2)
Change in estimates related to        prior year tax liabilities	1.9	1	(2.6)	(2)	(.4)	-	1.1	-
Software amortization	.9	-	.8	-	2.4	1	2.3	1
Deferred tax adjustment	3.2	2	-	-	3.2	1	-	-
Other, net	(1.3)	(1)	(1.3)	(1)	(1.8)	(1)	(2.6)	(1)
Total Consolidated Income Tax Expense	$ 80.2	32%	$ 62.3	37%	$140.3	34%	$136.7	39%

     During the third quarter of 2007, PHI completed an analysis of its deferred tax accounts as of December 31, 2006, including the deferred tax accounts of its wholly owned subsidiaries, Pepco, DPL and ACE. As a result of this analysis, PHI recorded a $3.2 million charge to income tax expense for the three months ended September 30, 2007, which is included in "Deferred tax adjustment" in the reconciliation provided above. The deferred tax adjustments relating to DPL and ACE were recorded as a $0.6 million increase to goodwill at the consolidated level, as they were determined to be errors in recording deferred tax assets and liabilities in those entities at the time of the acquisition of Conectiv by PHI in August 2002.

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Maryland Income Tax Refund

     On August 1, 2007, Pepco entered into a settlement agreement with the Comptroller of Maryland pursuant to which Pepco received a refund of state income taxes paid in the amount of approximately $30 million, which was due to an increase in the tax basis of certain assets sold in 2000. The refund was recorded in the third quarter of 2007, net of Federal income taxes due on the refund and related professional fee expenses incurred in connection with the matter, and resulted in a $17.7 million increase to PHI's net income.

Resolution of Uncertain Tax Positions

     In June 2007, DPL entered into a settlement with the State of Delaware related to the allocation of a gain on the sale of real property that occurred in 2001, pursuant to which DPL has made a cash payment of approximately $12 million, consisting of $7.4 million in tax and $4.6 million in interest. DPL's tax reserves for this issue exceed by $2.8 million the settlement amount. The excess reserves were credited to DPL's income tax expense in the second quarter. Because the matter involved a Conectiv tax contingency that existed at the time of the acquisition of Conectiv in August 2002, an additional adjustment of $1.9 million has been recorded in Corporate and Other to eliminate a portion of the tax benefit recorded by DPL.

Resolution of Certain Internal Revenue Service Audit Matters

     In the second quarter of 2006, PHI resolved certain, but not all, tax matters that were raised in Internal Revenue Service audits related to the 2001 and 2002 tax years. Adjustments recorded during the second quarter of 2006 related to these resolved tax matters resulted in an increase in net income of $6.3 million ($2.5 million for Power Delivery and $5.4 million for Other Non-Regulated, partially offset by an unfavorable $1.6 million impact in Corporate and Other). To the extent that the matters resolved related to tax contingencies from the Conectiv companies that existed at the August, 2002 merger date, in accordance with accounting rules, an additional adjustment of $9.1 million ($3.1 million related to Power Delivery and $6.0 million related to Other Non-Regulated) has been recorded in Corporate and Other to eliminate the tax benefits recorded by the lines of business against the goodwill balance that resulted from the merger.

Amended and Restated 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 indebted ness incurred under the facility is unsecured.

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     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 use the facility to borrow funds for general corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties made by the borrower at the time the amended and restated credit agreement was entered into also must be true at the time the facility is utilized, and the borrower must be in compliance with specified covenants, including the financial covenant described below. However, a material adverse change in the borrower's business, property, and results of operations or financial condition subsequent to the entry into the amended and restated credit agreement is not a condition to the availability of credit under the facility. Among the covenants to which each of the companies is subject are (i) the requirement that each borrowin g company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the amended and restated credit agreement, which calculation excludes certain trust preferred securities and deferrable interest subordinated debt from the definition of total indebtedness (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than sales and dispositions permitted by the amended and restated credit agreement, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than liens permitted by the amended and restated credit agreement. The agreement does not include any rating triggers.

Debt

     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 with the proceeds of a June 2007 offering of $250 million of 6.125% ten-year notes and short-term debt.

Restricted Cash

     Restricted cash represents cash either held or pledged as collateral that is restricted from use for general corporate purposes and cash that is specifically segregated, based on management's intent, to fund the future above-market capacity and energy purchase costs under the Panda PPA. Restricted cash is classified as current or non-current, consistent with the classification of the related liabilities.

Reclassifications

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

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New Accounting Standards

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

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

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

     In February 2006, the FASB issued SFAS No. 155, "Accounting for Certain Hybrid Financial Instruments - an amendment of FASB Statements No. 133 and 140" (SFAS No. 155). SFAS No. 155 amends SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," and SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." SFAS No. 155 resolves issues addressed in SFAS No. 133 Implementation Issue No. D1, "Application of Statement 133 to Beneficial Interests in Securitized Financial Assets." SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity's first fiscal year that begins after September 15, 2006 (year ending December 31, 2007 for Pepco Holdings). Implementation of SFAS No. 155 did not have a material impact on Pepco Holdings' overall financial condition, results of operations, or cash flows.

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

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

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

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

     On June 28, 2006, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 06-3, "Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions" (EITF 06-3). EITF 06-3 provides guidance on an entity's disclosure of its accounting policy regarding the gross or net presentation of certain taxes and provides that if taxes included in gross revenues are significant, a company should disclose the amount of such taxes for each period for which an income statement is presented (i.e., both interim and annual periods). Taxes within the scope of EITF 06-3 are those that are imposed on and concurrent with a specific revenue-producing transaction. Taxes assessed on an entity's activities over a period of time are not within the scope of EITF 06-3. Pepco Holdings implemented EITF 06-3 during the first quarter of 2007. Taxes included in Pepco Holdings gross revenues were $89.7 million and $76.0 million for the three months ended Septe mber 30, 2007 and 2006, respectively, and $239.8 million and $201.3 million for the nine months ended September 30, 2007 and 2006, respectively.

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

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

     FSP FAS 13-2 is effective for the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for Pepco Holdings). A material change in the timing of cash flows under Pepco Holdings' cross-border leases as the result of a settlement with the Internal Revenue Service or a change in tax law would require an adjustment to the book value of the leases and a charge to earnings equal to the repricing impact of the disallowed deductions which could result in a material adverse effect on Pepco Holdings' overall financial condition, results of operations, and cash flows. For a further discussion, see "Federal Tax Treatment of Cross-border Leases" in Note (4), "Commitments and Contingencies."

     SFAS No. 157, "Fair Value Measurements"

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

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

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that SFAS No. 157 will have on its overall financial condition, results of operations, and cash flows.

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

     On September 8, 2006, the FASB issued FSP American Institute of Certified Public Accountants Industry Audit Guide, Audits of Airlines--"Accounting for Planned Major Maintenance Activities" (FSP AUG AIR-1), which prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods for all industries. FSP AUG AIR-1 is effective the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for Pepco Holdings). Implementation of FSP AUG AIR-1 did not have a material impact on Pepco Holdings' overall financial condition, results of operations, or cash flows.

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

     On September 20, 2006, the FASB ratified EITF Issue No. 06-5, "Accounting for Purchases of Life Insurance -- Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of Life Insurance" (EITF 06-5) which provides guidance on whether an entity should consider the contractual ability to surrender all of the individual-life policies (or certificates under a group life policy) together when determining the amount that could be realized in accordance with FTB 85-4, and whether a guarantee of the additional value associated with the group life policy affects that determination. EITF 06-5 provides that a policyholder should (i) determine the amount that could be realized under the insurance contract assuming the surrender of an individual-life by individual-life policy (or certificate by certificate in a group policy) and (ii) not discount the cash surrender value component of the amount that could be realized when c ontractual restrictions on the ability to surrender a policy exist unless contractual limitations prescribe that the cash surrender value component of the amount that could be realized is a fixed amount, in which case the amount that could be realized should be discounted in accordance with Accounting Principles Board of the American Institute of Certified Public Accountants Opinion 21. EITF 06-5 is effective for fiscal years beginning after December 15, 2006 (year ending December 31, 2007 for Pepco Holdings). Implementation of EITF 06-5 did not have a material impact on Pepco Holdings' overall financial condition, results of operations, cash flows, or footnote disclosure requirements.

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

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

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registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to the issuance of FSP EITF 00-19-2, this guidance is effective for financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years (year ending December 31, 2007 for Pepco Holdings). Pepco Holdings implemented FSP EITF 00-19-2 during the first quarter of 2007. The implementation did not have a material impact on its overall financial condition, results of operations, or cash flows.

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

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

   SFAS No. 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company's choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. SFAS No. 159 does not eliminate disclosure requirements included in other accounting standards.

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

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

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

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(year ending December 31, 2008 for Pepco Holdings), with early adoption permitted. Pepco Holdings has evaluated the impact of FSP FIN 39-1 and has determined that it does not have a material impact on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

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

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

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

     EITF Issue No. 06-11 applies prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years beginning after December 15, 2007, and interim periods within those fiscal years (year ending December 31, 2008 for Pepco Holdings). Early application is permitted as of the beginning of a fiscal year for which interim or annual financial statements have not yet been issued. Retrospective application to previously issued financial statements is prohibited. Entities must disclose the nature of any change in their accounting policy for income tax benefits of dividends on share-based payment awards resulting from the adoption of this guidance. Pepco Holdings is currently in the process of evaluating the impact that EITF Issue No. 06-11 will have on its overall financial condition, results of operations, cash flows and footnote disclosure requirements.

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(3)  SEGMENT INFORMATION

     Based on the provisions of SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," Pepco Holdings' management has identified its operating segments at September 30, 2007 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. Prior to 2007, intrasegment revenues and expenses were not eliminated at the segment level for purposes of presenting segment financial results but rather were eliminated for PHI's consolidated results through the "Corp. & Other" column. Beginning in 2007, intrasegment revenues and expenses are eliminated at the segment level. Segment results for the three months and nine months ended September 30, 2006, have been reclassified to conform to the current presentation. Segment financial information for the three and nine months ended September 30, 2007 and 2006, is as follows.

		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
Note:
(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 state income tax refund.

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		Three Months Ended September 30, 2006                                        (Millions of dollars)
			Competitive Energy Segments
		Power Delivery	Conectiv Energy	Pepco Energy Services	Other     Non-     Regulated	Corp.  & Other (a)	PHI   Cons.
Operating Revenue		$1,660.7	$  566.8 (b)(e)	$488.3	$     21.4	$(147.3) (e)	$  2,589.9
Operating Expense (c)		1,488.3 (b)	520.5 (e)	488.8 (d)	1.9	(152.4) (e)	2,347.1
Operating Income		172.4	46.3	(.5)	19.5	5.1	242.8
Interest Income		3.4	2.0 (e)	1.0	1.8 (f)	(3.9) (e)(f)	4.3
Interest Expense		46.3	9.7 (e)	1.5	9.7 (f)	19.8  (e)(f)	87.0
Other Income		4.7	.1	.9	.7	.1	6.5
Preferred Stock    Dividends		.3	-	-	.6	(.6)	.3
Income Taxes		50.4	16.2	.2	1.9	(6.4)	62.3
Net Income (Loss)		83.5	22.5	(.3)	9.8	(11.5)	104.0
Total Assets		8,978.0	1,837.6	698.1	1,515.6	965.7	13,995.0
Construction    Expenditures		$  102.4	$     2.5	$   1.8	$         -	$    1.3	$    108.0
Note:
(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 $(147.6) million for Operating Revenue, $(145.9) million for Operating Expense, $(25.1) million for Interest Income, $(24.5) 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 $144.1 million for the three months ended September 30, 2006.
(c)	Includes depreciation and amortization of $110.4 million, consisting of $95.8 million for Power Delivery, $9.0 million for Conectiv Energy, $3.0 million for Pepco Energy Services, $.5 million for Other Non-Regulated and $2.1 million for Corp. & Other.
(d)	Includes $12.6 million of impairment losses ($7.9 million after-tax) on certain energy services business assets.
(e)	Due to the reclassification referred to in the introductory paragraph, the Conectiv Energy segment does not include $66.8 million of intrasegment operating revenue and operating expense and $6.9 million of intrasegment interest income and interest expense. Accordingly, the Corp. & Other column does not include an elimination for these amounts.
(f)	Due to the reclassification referred to in the introductory paragraph, the Other Non-Regulated segment does not include $47.7 million of intrasegment interest income and interest expense. Accordingly, the Corp. & Other column does not include an elimination for these amounts.

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		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
Note:
(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 state income tax refund.

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		Nine Months Ended September 30, 2006                                          (Millions of dollars)
			Competitive Energy Segments
		Power Delivery	Conectiv Energy	Pepco Energy Services	Other     Non-     Regulated	Corp.  & Other (a)	PHI     Cons.
Operating Revenue		$4,014.9	$1,551.3 (b)(g)	$1,205.5	$     70.6	$(383.9) (g)	$  6,458.4
Operating Expense (c)		3,624.9 (b)	1,471.8 (g)	1,183.0 (e)	5.2	(386.4) (g)	5,898.5
Operating Income		390.0	79.5	22.5	65.4	2.5	559.9
Interest Income		8.2	6.1 (g)	2.0	4.9 (h)	(9.2) (g)(h)	12.0
Interest Expense		135.0	27.1 (g)	3.2	28.6 (h)	59.9  (g)(h)	253.8
Other Income		14.0	11.8 (d)	1.5	3.3	1.0	31.6
Preferred Stock    Dividends		1.8	-	-	1.8	(2.6)	1.0
Income Taxes		106.3	29.1	9.4	5.2	(13.3)	136.7
Net Income (Loss)		169.1 (f)	41.2	13.4	38.0 (f)	(49.7) (f)	212.0
Total Assets		8,978.0	1,837.6	698.1	1,515.6	965.7	13,995.0
Construction    Expenditures		$  335.9	$      7.5	$      5.7	$          -	$      7.2	$     356.3
Note:
(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 $(385.7) million for Operating Revenue, $(381.2) million for Operating Expense, $(67.4) million for Interest Income, $(65.6) 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 $370.3 million for the nine months ended September 30, 2006.
(c)	Includes depreciation and amortization of $318.7 million, consisting of $275.4 million for Power Delivery, $27.2 million for Conectiv Energy, $8.8 million for Pepco Energy Services, $1.4 million for Other Non-Regulated and $5.9 million for Corp. & Other.
(d)	Includes $12.3 million gain ($7.9 million after tax) on the sale of its equity interest in a joint venture which owns a wood burning cogeneration facility in California.
(e)	Includes $19.1 million of impairment losses ($12.1 million after tax) on certain energy services business assets.
(f)	Includes the total favorable impact of $6.3 million related to tax matters that were resolved during the second quarter of 2006 ($2.5 million for Power Delivery and $5.4 million for Other Non-Regulated, partially offset by an unfavorable $1.6 million in Corp. & Other). Additionally Corp. & Other includes the elimination (against the goodwill generated by the merger) of the tax benefits recorded by the lines of business in the amount of $9.1 million ($3.1 million related to Power Delivery and $6.0 million related to Other Non-Regulated). Also includes the total favorable impact of $2.6 million recorded during the third quarter of 2006 that resulted from changes in estimates related to prior year tax liabilities subject to audit ($4.1 million for Power Delivery, partially offset by an unfavorable $1.5 million for Corp. & Other). Corp. & Other also includes the elimination (increasing goodwill generated by the merger) of the expense recorded by the segments in the amount of $.6 million ($.4 million for Power Delivery and $.2 million for Other Non-Regulated).
(g)	Due to the reclassification referred to in the introductory paragraph, the Conectiv Energy segment does not include $147.8 million of intrasegment operating revenue and operating expense and $20.4 million of intrasegment interest income and interest expense. Accordingly, the Corp. & Other column does not include an elimination for these amounts.
(h)	Due to the reclassification referred to in the introductory paragraph, the Other Non-Regulated segment does not include $142.4 million of intrasegment interest income and interest expense. Accordingly, the Corp. & Other column does not include an elimination for these amounts.

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(4)  COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Final Resolution of Mirant Bankruptcy Matter

     In 2000, Pepco sold substantially all of its electricity generating assets to Mirant Corporation (formerly Southern Energy, Inc.) and certain of its subsidiaries. In July 2003, Mirant and certain of its subsidiaries filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas (the Bankruptcy Court). In December 2005, the Bankruptcy Court approved the Plan of Reorganization (the Reorganization Plan) of Mirant and the Mirant business emerged from bankruptcy in January 2006, as a new corporation of the same name (together with its predecessors, Mirant).

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

     Power Purchase Agreement

     The Panda PPA obligates Pepco to purchase from Panda 230 megawatts of energy and capacity annually through 2021. At the time of the sale of Pepco's generating assets to Mirant, the purchase price of the energy and capacity under the Panda PPA was, and since that time has continued to be, substantially in excess of the market price. As a part of the Asset Purchase and Sale Agreement, Pepco entered into a "back-to-back" arrangement with Mirant. Under this arrangement, Mirant was obligated through 2021 to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the Panda PPA at a price equal to Pepco's purchase price from Panda (the PPA-Related Obligations).

     The SMECO Agreement

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

     Settlement Agreements with Mirant

     In May 2006, Pepco, PHI, and certain affiliated companies entered into a Settlement Agreement and Release (the Settlement Agreement) with Mirant, which settled all outstanding issues between the parties arising from or related to the Mirant bankruptcy, as more fully described below. Separately, Mirant and SMECO entered into a Settlement Agreement and Release (the SMECO Settlement Agreement), which provides that Mirant will assume, rather

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than reject, the SMECO Agreement. This assumption ensures that Pepco will not incur liability to SMECO as the guarantor of the SMECO Agreement due to the rejection of the SMECO Agreement, although Pepco will continue to guarantee to SMECO the future performance of Mirant under the SMECO Agreement.

     In August 2006, the Bankruptcy Court issued an order approving the Settlement Agreement and the SMECO Settlement Agreement. This order was appealed to the United States District Court for the Northern District of Texas (the District Court) by certain holders of Mirant bankruptcy claims who had objected to approval of the Settlement Agreement and the SMECO Settlement Agreement before the Bankruptcy Court. In December 2006, the District Court issued an order affirming the Bankruptcy Court's order approving the Settlement Agreement and the SMECO Settlement Agreement. In January 2007, the parties that appealed the Bankruptcy Court's order filed a notice of appeal of the District Court's order with the United States Court of Appeals for the Fifth Circuit (the Fifth Circuit). On August 8, 2007, the Fifth Circuit, on the basis of a settlement reached between Mirant and the objecting creditors, issued an order dismissing the appeal with prejudice.

     Under the terms of the Settlement Agreement, Mirant assumed the Asset Purchase and Sale Agreement, except for the PPA-Related Obligations, and Pepco was to receive $520 million, consisting of (i) $450 million in damages as compensation from Mirant for rejecting the PPA-Related Obligations and (ii) $70 million in settlement of other Pepco damage claims against the Mirant bankruptcy estate. To implement the settlement, the following transactions occurred.

· Pepco received from Mirant shares of Mirant stock with an estimated value of $520.0 million, which were liquidated, resulting in net cash proceeds of $522.2 million, after transaction costs.

· Pepco reimbursed Mirant $2.2 million, representing the excess of the amount of the net proceeds of $522.2 million over the settlement amount of $520.0 million.

· Pepco reimbursed Mirant $70.0 million for the amount previously received by Pepco from Mirant in August 2006, which became due in accordance with the terms of the Settlement Agreement as a result of its approval by the Bankruptcy Court. At the time of receipt, Pepco did not recognize any portion of the payment in earnings pending the appeal of the Bankruptcy Court order.

· Pepco reimbursed Mirant $36.1 million, representing the net above-market costs paid by Mirant under the Panda PPA "back-to-back" arrangement during the period from June 1, 2006, the date the parties entered into the Settlement Agreement, to August 8, 2007, the date the objecting creditors' appeal was dismissed by the Fifth Circuit.

     In addition, under the Settlement Agreement, all pending appeals, adversary actions and other contested matters between Pepco and Mirant were dismissed with prejudice and each party released the other from any and all claims relating to the Mirant bankruptcy.

     Pepco intends to use the $413.9 million of the settlement payment (the $450 million portion, less the $36.1 million that Pepco has reimbursed to Mirant), plus interest earned, to pay for

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future above-market capacity and energy purchases under the Panda PPA over the remaining life of the Panda PPA through 2021. The $413.9 million is being accounted for as non-current restricted cash, and a corresponding non-current regulatory liability has been recorded, based on Pepco's expectation that both the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC) will issue orders directing Pepco to use the proceeds, and any earnings on the proceeds, solely to offset the future above-market costs. Management intends to seek these orders from the DCPSC and the MPSC in the fourth quarter of 2007.

     Of the $70.0 million received in settlement of other Pepco damage claims, $33.4 million has been recorded as a reduction of operating expenses, $21.0 million has been recorded as a reduction in a net pre-petition receivable claim from Mirant, $15.0 million has been recorded as a reduction in the capitalized costs of certain property plant and equipment and the remaining $.6 million has been recorded as a liability to reimburse SMECO for certain legal costs associated with the settlement.

Rate Proceedings

     In electric service distribution base rate cases filed by Pepco in the District of Columbia and Maryland and by DPL in Maryland, Pepco and DPL proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers. Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the approved revenue-per-customer amount. The BSA will increase rates if actual distribution revenues fall below the level approved by the applicable commission and will decrease rates if actual distribution revenues are above the approved level. The result will be that, over time, the utility would collect its authorized revenues for distribution deliveries. As a consequence, a BSA "decouples" revenue from unit sales consumption and ties the growth in revenues to the growth in the number of customers. Some advantages of the BSA are that it (i)& nbsp;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 discussion of the respective base rate proceedings.

     Delaware

     On August 31, 2006, DPL submitted its 2006 Gas Cost Rate (GCR) filing to the Delaware Public Service Commission (DPSC), which permits DPL to recover gas procurement costs through customer rates. In October 2006, the DPSC issued an initial order approving the proposed rates, which became effective November 1, 2006, subject to refund pending final DPSC approval after evidentiary hearings. In February 2007, DPL submitted an additional filing to the DPSC that proposed an additional 4.3% decrease in the GCR effective April 1, 2007, in compliance with its gas service tariff and to ensure collections are more aligned with expenses. In March 2007, the DPSC approved the rate decrease, subject to refund pending final DPSC approval after evidentiary hearings. On July 17, 2007, the DPSC granted final approval for the GCR, as filed.

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     On September 4, 2007, DPL submitted its 2007 GCR filing to the DPSC. On September 18, 2007, the DPSC issued an initial order approving a 5.7% decrease in the level of the GCR, which will become effective November 1, 2007, subject to refund and pending final DPSC approval after evidentiary hearings.

     District of Columbia

     On December 12, 2006, Pepco submitted an application to the DCPSC to increase electric distribution base rates, including a proposed BSA. The application to the DCPSC requested an annual increase of approximately $46.2 million or an overall increase of 13.5%, reflecting a proposed return on equity (ROE) of 10.75%. In the alternative, the application requested an annual increase is $50.5 million or an overall increase of 14.8%, reflecting an ROE of 11.00%, if the BSA is not approved. Hearings were held in the case in June 2007. A DCPSC decision is expected in the fourth quarter of 2007.

     Maryland

     On July 19, 2007, the MPSC issued orders in the electric service distribution rate cases filed by DPL and Pepco. The DPL order approved a temporary annual increase in distribution rates of approximately $14.9 million (including a decrease in annual depreciation expense of approximately $0.9 million). The Pepco order approved a temporary 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 orders each provided that the rate increases are effective as of June 16, 2007, and will remain in effect for an initial period of nine months from the date of the order (or until April 19, 2008). The temporary rates are subject to a Phase II proceeding in which the MPSC will consider the results of audits of each company's cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates is required. For each of the utilities, the MPSC approved a proposed BSA.

     New Jersey

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

     ACE projects that, as of September 30, 2007 (based upon actual data through August 2007), the NGC, which is intended primarily to recover the above-market component of payments made by ACE under non-utility generation contracts and stranded costs associated with those commitments, will have an over-recovery balance of $216.2 million. The filing proposes that
the NGC balance, including interest, be amortized and returned to ACE customers over a four-year period, beginning October 1, 2007.

     ACE also projects that, as of September 30, 2007 (based upon actual data through August 2007), the SBC, which is intended to allow ACE to recover certain costs involved with various NJBPU-mandated social programs, will have an under-recovery of approximately $19.6 million,

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primarily due to increased costs associated with funding the New Jersey Clean Energy Program. In addition, ACE has requested an increase to the SBC to reflect the funding levels approved by the NJBPU of $20.4 million for the period October 1, 2007 through September 30, 2008, which will require the SBC to recover a total of $40 million for the period of October 1, 2007 to September 30, 2008 (based upon actual data through August 2007).

     The net impact of the proposed adjustments to the NGC and the SBC, including associated changes in sales and use tax, is an overall rate decrease of approximately $129.9 million for the period October 1, 2007 through September 30, 2008 (based upon actual data through August 2007). The proposed adjustments and the corresponding changes in customer rates are subject to the approval of the NJBPU. If approved and implemented, ACE anticipates that the revised rates will remain in effect until September 30, 2008, subject to an annual true-up and change each year thereafter. The proposed adjustments and the corresponding changes in customer rates remain under review by the NJBPU and have not yet been implemented.

ACE Restructuring Deferral Proceeding

     Pursuant to orders issued by the NJBPU under the New Jersey Electric Discount and Energy Competition Act (EDECA), beginning August 1, 1999, ACE was obligated to provide BGS to retail electricity customers in its service territory who did not elect to purchase electricity from a competitive supplier. For the period August 1, 1999 through July 31, 2003, ACE's aggregate costs that it was allowed to recover from customers exceeded its aggregate revenues from supplying BGS. These under-recovered costs were partially offset by a $59.3 million deferred energy cost liability existing as of July 31, 1999 (LEAC Liability) related to ACE's Levelized Energy Adjustment Clause and ACE's Demand Side Management Programs. ACE established a regulatory asset in an amount equal to the balance of under-recovered costs.

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

     In July 2004, the NJBPU issued a final order in the restructuring deferral proceeding confirming a July 2003 summary order, which (i) permitted ACE to begin collecting a portion of the deferred costs and reset rates to recover on-going costs incurred as a result of EDECA, (ii) approved the recovery of $125 million of the deferred balance over a ten-year amortization period beginning August 1, 2003, (iii) transferred to ACE's then pending base rate case for further consideration approximately $25.4 million of the deferred balance (the base rate case ended in a settlement approved by the NJBPU in May 2005, the result of which is that any net rate impact from the deferral account recoveries and credits in future years will depend in part on whether rates associated with other deferred accounts considered in the case continue to generate over-collections relative to costs), and (iv) estimated the overall deferral balance as of July 31, 2003 at $195 million, of whic h $44.6 million was disallowed recovery by ACE. Although ACE believes the record does not justify the level of disallowance imposed by the NJBPU in the final order, the $44.6 million of disallowed incurred costs were reserved during the years 1999 through 2003 (primarily 2003) through charges to earnings, primarily in the

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operating expense line item "deferred electric service costs," with a corresponding reduction in the regulatory asset balance sheet account. In 2005, an additional $1.2 million in interest on the disallowed amount was identified and reserved by ACE. In August 2004, ACE filed a notice of appeal with respect to the July 2004 final order with the Appellate Division of the Superior Court of New Jersey (the Appellate Division), which hears appeals of the decisions of New Jersey administrative agencies, including the NJBPU. On August 9, 2007, the Appellate Division, citing deference to the factual and policy findings of the NJBPU, affirmed the NJBPU's decision in its entirety, rejecting challenges from ACE and the Division of Rate Counsel. On September 10, 2007, ACE filed an application for certification to the New Jersey Supreme Court. Though ACE continues to believe that the position it took before the Appellate Division is correct, there is no assurance that the New Jersey Supreme Court will agree to hear this discretionary appeal.

Divestiture Cases

     District of Columbia

     Final briefs on Pepco's District of Columbia divestiture proceeds sharing application were filed with the DCPSC in July 2002 following an evidentiary hearing in June 2002. That application was filed to implement a provision of Pepco's DCPSC-approved divestiture settlement that provided for a sharing of any net proceeds from the sale of Pepco's generation-related assets. One of the principal issues in the case is whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code (IRC) and its implementing regulations. As of September 30, 2007, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6.5 million and $5.8 million, respectively.

     Pepco believes that a sharing of EDIT and ADITC would violate the Internal Revenue Service (IRS) normalization rules. Under these rules, Pepco could not transfer the EDIT and the ADITC benefit to customers more quickly than on a straight line basis over the book life of the related assets. Since the assets are no longer owned there is no book life over which the EDIT and ADITC can be returned. If Pepco were required to share EDIT and ADITC and, as a result, the normalization rules were violated, Pepco would be unable to use accelerated depreciation on District of Columbia allocated or assigned property. In addition to sharing with customers the generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS an amount equal to Pepco's District of Columbia jurisdictional generation-related ADITC balance ($5.8 million as of September 30, 2007), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($4.2  ;million as of September 30, 2007) in each case as those balances exist as of the later of the date a DCPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the DCPSC order becomes operative.

     In March 2003, the IRS issued a notice of proposed rulemaking (NOPR), which would allow for the sharing of EDIT and ADITC related to divested assets with utility customers on a prospective basis and at the election of the taxpayer on a retroactive basis. In December 2005 a revised NOPR was issued which, among other things, withdrew the March 2003 NOPR and eliminated the taxpayer's ability to elect to apply the regulation retroactively. Comments on the revised NOPR were filed in March 2006, and a public hearing was held in April 2006. Pepco

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filed a letter with the DCPSC in January 2006, in which it has reiterated that the DCPSC should continue to defer any decision on the ADITC and EDIT issues until the IRS issues final regulations or states that its regulations project related to this issue will be terminated without the issuance of any regulations. Other issues in the divestiture proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.

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

     Maryland

    Pepco filed its divestiture proceeds plan application with the MPSC in April 2001. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that has been raised in the District of Columbia case. See the discussion above under "Divestiture Cases -- District of Columbia." As of September 30, 2007, the Maryland allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $9.1 million and $10.4 million, respectively. Other issues deal with the treatment of certain costs as deductions from the gross proceeds of the divestiture. In November 2003, the Hearing Examiner in the Maryland proceeding issued a proposed order with respect to the application that concluded that Pepco's Maryland divestiture settlement agreement provided for a sharing between Pepco and customers of the EDIT and ADITC associated with the sold assets. Pepco believes that such a sharing would violate the normalization rules (discussed ab ove) 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, 2007), 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, 2007), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($7.5 million as of September 30, 2007), 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 determin ation that only one-half of the severance payments that Pepco included in its calculation of corporate reorganization costs should be deducted from the sales proceeds before sharing of the net gain between Pepco and customers. Pepco filed a letter with the MPSC in January 2006, in which it has reiterated that the MPSC should continue to defer any decision on the ADITC and EDIT issues until the IRS issues final regulations or states that its regulations project related to this issue will be terminated without the issuance of any regulations.

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     In December 2003, Pepco appealed the Hearing Examiner's decision to the MPSC as it relates to the treatment of EDIT and ADITC and corporate reorganization costs. The MPSC has not issued any ruling on the appeal and Pepco does not believe that it will do so until action is taken by the IRS as described above. However, depending on the ultimate outcome of this proceeding, Pepco could be required to share with its customers approximately 50 percent of the EDIT and ADITC balances described above in addition to the additional gain-sharing payments relating to the disallowed severance payments (which Pepco is not contesting). Such additional payments would be charged to expense in the quarter and year in which a final decision is rendered and could have a material adverse effect on results of operations for those periods. However, neither PHI nor Pepco believes that additional gain-sharing payments, if any, or the ADITC-related payments to the IRS, if required, would have a mat erial adverse impact on its financial position or cash flows.

     New Jersey

     In connection with the divestiture by ACE of its nuclear generating assets, the NJBPU in July 2000 preliminarily determined that the amount of stranded costs associated with the divested assets that ACE could recover from ratepayers should be reduced by approximately $94.8 million, consisting of $54.1 million of accumulated deferred Federal income taxes (ADFIT) associated with accelerated depreciation on the divested nuclear assets, and $40.7 million of current tax loss from selling the assets at a price below the tax basis.

     The $54.1 million in deferred taxes associated with the divested assets' accelerated depreciation, however, is subject to the normalization rules. Due to uncertainty under Federal tax law regarding whether the sharing of Federal income tax benefits associated with the divested assets, including ADFIT related to accelerated depreciation, with ACE's customers would violate the normalization rules, ACE submitted a request to the IRS for a Private Letter Ruling (PLR) to clarify the applicable law. The NJBPU delayed its final determination of the amount of recoverable stranded costs until after the receipt of the PLR.

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

     On June 9, 2006, ACE submitted a letter to the NJBPU, requesting that the NJBPU conduct proceedings to finalize the determination of the stranded costs associated with the sale of ACE's nuclear assets in accordance with the PLR. In the absence of an NJBPU action regarding ACE's request, on June 22, 2007, ACE filed a motion requesting that the NJBPU issue an order finalizing the determination of such stranded costs in accordance with the PLR. On October 24, 2007, the NJBPU approved a stipulation resolving the ADFIT issue and issued a clarifying order, which concludes that the $94.8 million in stranded cost reduction, including the $54.1 million in ADFIT, does not violate the IRS normalization rules. In explaining this result, the NJBPU stated that (i) its earlier orders determining ACE's recoverable stranded costs "net of tax" did not cause ADFIT associated with certain divested nuclear assets to reduce stranded costs otherwise recoverable from ACE's ratepaye rs, and (ii) because the Market Transition Charge-Tax component of the stranded cost recovery was intended by the NJBPU to gross-up "net of tax" stranded costs, thereby ensuring and establishing that the ADFIT balance was not flowed through to ratepayers, the normalization rules were not violated.

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Default Electricity Supply Proceedings

     Virginia

     As discussed below under the heading "DPL Sale of Virginia Operations," DPL has entered into an agreement to sell substantially all of its Virginia electric service operations.

     On April 2, 2007, DPL filed an application with Virginia State Corporation Commission (VSCC) to adjust its Default Service rates covering the period June 1, 2007 to May 31, 2008. The proposed rates for this service during the first month of this period (June 2007) are based on the fuel proxy rate calculation described below. The proposed rates for the remaining 11 months of the period (July 1, 2007 to May 31, 2008) reflect the fuel cost of Default Service supply based upon the results of the competitive bidding wholesale procurement process. The calculations in the application result in a rate decrease of approximately $1.7 million for the period, June 1 to June 30, 2007, and an increase of approximately $4.2 million for the period, July 1, 2007 to May 31, 2008, resulting in an overall annual rate increase of approximately $2.5 million.

     The "fuel proxy rate calculation" was established under a Memorandum of Agreement (MOA) that DPL entered into with the staff of the VSCC in connection with the approval of DPL's divestiture of its generation assets in 2000, and provides for the calculation of the fuel rate portion of Default Service rates that reflect an approximation of the fuel costs that DPL would have incurred had it retained its generating assets. Since June 1, 2006, use of the proxy rate calculation has resulted in DPL being unable to recover fully its cost of providing Default Service. The April 2007 rate application reflects DPL's position that the use of the fuel proxy rate calculation to establish Default Service rates terminated on July 1, 2007, and effective that date, it should be permitted to charge customers market based fuel costs. However, pursuant to an order dated June 8, 2007, the VSCC denied the July 1, 2007 rate increase, based on its conclusion that the MOA's provisions relating to f uel costs did not end effective June 30, 2007. As a result of this decision, DPL under-recovered its cost of providing Default Service by approximately $1.9 million between June 1, 2007 and the September 30, 2007 expiration of the Default Service contract. Any further under-recovery will be determined by the difference between the fuel proxy rate calculation and market rates for the fuel portion of Default Service and the timing of completion of the sale of DPL's Virginia electric operations as described below under the heading "DPL Sale of Virginia Operations." A fixed price, partial hedge has been purchased for the period through December 31, 2007, which should substantially limit DPL's exposure to market price fluctuations during that period.

     DPL filed a complaint for a declaratory order and preliminary injunctive relief with the U.S. District Court for the Eastern District of Virginia (the Virginia District Court). On July 23, 2007, the Virginia District Court dismissed the complaint and denied injunctive relief, finding that the court lacked subject matter jurisdiction and stating that even if it had subject matter jurisdiction, it would abstain from exercising that jurisdiction to allow the Supreme Court of Virginia to consider the issues upon which the complaint was based.

     DPL currently is pursuing relief in both state and federal courts: On July 31, 2007, DPL filed a notice of appeal of the VSCC's orders with the Supreme Court of Virginia; and on August 31, 2007, DPL filed an appeal from the Virginia District Court's order with the U. S. Court of Appeals for the Fourth Circuit. The sale of DPL's Virginia electric operations as described below under the heading "DPL Sale of Virginia Operations" is not contingent upon resolution of

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any of the matters that are at issue in these proceedings. If the sale of the Virginia electric operations is completed, the effect, if any, on these proceedings is not determinable at this time.

ACE Sale of B.L. England Generating Facility

     On February 8, 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy Investments, LLC, for which it received proceeds of approximately $9 million, after giving effect to certain post-closing adjustments. At the time of the sale, RC Cape May and ACE agreed to submit to arbitration the issue of whether RC Cape May, under the terms of the purchase agreement, must pay to ACE an additional $3.1 million as part of the purchase price. Arbitration hearings were held October 15 through 17, 2007. An oral argument is scheduled for January 15, 2008, and a decision by the arbitrators is expected in February 2008. As part of the sale, RC Cape May assumed certain liabilities associated with the B.L. England generating station, including substantially all environmental liabilities.

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

     The sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized. ACE anticipates that approximately $9 million to $10 million of additional regulatory assets related to B.L. England may, subject to NJBPU approval, be eligible for recovery as stranded costs. Approximately $47 million in emission allowance credits associated with B. L. England were monetized for the benefit of ACE's ratepayers pursuant to the NJBPU order approving the sale. Net proceeds from the sale of the plant and monetization of the emission allowance credits, will be credited to ACE's ratepayers in accordance with the requirements of EDECA and NJBPU orders. The appropriate mechanism for crediting the net proceeds from the sale of the plant and the monetized emission allowance credits to ratepayers is being determined in a Phase II proceeding which is currently pending before the NJBPU.

DPL Sale of Virginia Operations

     On June 13, 2007, DPL entered into agreements (i) to sell to A&N Electric Cooperative (A&N) all of its assets principally related to DPL's business of distributing retail electric services to customers located on the Eastern Shore of Virginia, including real and personal property, accounts receivable and customer deposits, for a purchase price of approximately $39.8 million, subject to closing adjustments, and (ii) to sell to Old Dominion Electric Cooperative (ODEC) certain assets principally related to DPL's provision of wholesale electric transmission services located on the Eastern Shore of Virginia, for a purchase price of approximately $4.8 million, subject to closing adjustments. Each of A&N and ODEC will assume certain post-closing

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liabilities and unknown pre-closing liabilities related to the respective assets they are purchasing (including, in the A&N transaction, most environmental liabilities), except that DPL will remain liable for unknown pre-closing liabilities if they become known within six months after the respective closing dates. On October 9, 2007, FERC granted approval of an interconnection agreement and a facilities agreement needed for the completion of the ODEC transaction. On October 19, 2007, the VSCC issued an order approving both transactions. Northern Virginia Electric Cooperative (NOVAC) intervened in the VSCC proceedings, opposing the DPL sales to A&N and ODEC. NOVAC may file a petition for reconsideration within 20 days of the order. They also may appeal the VSCC order within 30 days. If filed, this would be considered an appeal "of right," which means the Virginia Supreme Court must hear the appeal. DPL expects the transactions to close during the fourth quarter of 2007, contingent upon the r eceipt of required final, non-appealable regulatory approvals. These sales, if completed, will not result in a material financial gain or loss to DPL.

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, 2007, 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 have been tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement. Under the terms of the Settlement Agreement, Mirant has agreed to assume this contractual obligation. For a description of the Settlement Agreement, see the discussion of the resolution of the Mirant bankruptcy matter above.

     While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) is approximately $360 million, PHI and Pepco believe the amounts claimed by current plaintiffs are greatly exaggerated. The amount of total liability, if any, and any related insurance recovery cannot be determined at this time; however, based on information and relevant circumstances known at this time, neither PHI nor Pepco believes these suits will have a material adverse effect on its financial position, results of operations or cash flows. However, if an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco's and PHI's financial position, results of operations or cash flows.

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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 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-heritage 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 May 2007, the PHI Parties filed a motion for summary judgment at the close of discovery. This motion was granted by the Delaware District Court on September 19, 2007. On October 12, 2007, the plaintiffs filed an appeal of the decision to the U.S. Court of Appeals for the Third Circuit.

     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 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.

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     Cambridge, Maryland Site. In July 2004, DPL entered into an administrative consent order (ACO) with the Maryland Department of the Environment (MDE) to perform a Remedial Investigation/Feasibility Study (RI/FS) to further identify the extent of soil, sediment and ground and surface water contamination related to former manufactured gas plant (MGP) operations at a Cambridge, Maryland site on DPL-owned property and to investigate the extent of MGP contamination on adjacent property. The MDE has approved the RI and DPL submitted a final FS to MDE on February 15, 2007. The costs of cleanup (as determined by the RI/FS and subsequent negotiations with MDE) are anticipated to be approximately $3.5 million. The remedial action will include dredging activities within Cambridge Creek, which are expected to take place as early as November 2007, and soil excavation on DPL's and adjacent property as early as January 2008. The final cleanup costs will include protective me asures to control contaminant migration during the dredging activities and improvements to the existing shoreline dock.

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

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

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

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     As of September 30, 2007, Pepco had accrued $1.7 million to meet its liability for a remedy at the Metal Bank/Cottman Avenue site. While final costs to Pepco of the settlement have not been determined, Pepco believes that its liability at this site will not have a material adverse effect on its financial position, results of operations or cash flows.

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

     Delilah Road Landfill Site. In November 1991, the New Jersey Department of Environmental Protection (NJDEP) identified ACE as a PRP at the Delilah Road Landfill site in Egg Harbor Township, New Jersey. In 1993, ACE, along with other PRPs, signed an ACO with NJDEP to remediate the site. The soil cap remedy for the site has been completed and the NJDEP conditionally approved the report submitted by the parties on the implementation of the remedy in January 2003. In March 2004, NJDEP approved a Ground Water Sampling and Analysis Plan. Positive results of groundwater monitoring events have resulted in a reduced level of groundwater monitoring. In August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site. Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years and to continue quarterly groundwater monitoring. In Sept ember 2007, NJDEP approved the PRP group's December 2006 petition seeking approval of 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 request for annual groundwater monitoring thereafter. In August 2007, the PRP group agreed to reimburse EPA's costs in the amount of $81,400 in full satisfaction of EPA's claims for all past and future response costs relating to the site (of which ACE's share is one-third) and in October 2007, EPA and the PRP group entered into a tolling agreement to permit the parties sufficient time to execute a final settlement agreement. This settlement agreement will allow the EPA to reopen the settlement in the event of new information or unknown conditions at the site. Based on information currently available, ACE anticipates that its share of additional cost associated with this site for post-remedy operation and maintenance will be approximately $555,000 to $600,000. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial position, results of operations or cash flows.

     Frontier Chemical Site. On June 29, 2007, ACE received a letter from the New York Department of Environmental Conservation (NYDEC) indicating that ACE is a PRP at the Frontier Chemical Waste Processing Company site in Niagara Falls, N.Y. The letter states that NYDEC has hazardous waste manifests indicating that ACE sent in excess of 7,500 gallons of manifested hazardous waste to the site. ACE informed NYDEC that it has entered into good faith negotiations with a coalescing PRP group to address ACE's responsibility at the site and in October 2007, ACE entered into an agreement with the other PRPs to form the PRP group. 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.

     Deepwater Generating Station. On December 27, 2005, NJDEP issued a Title V Operating Permit for Conectiv Energy's Deepwater Generating Station. The permit includes new limits on unit heat input. In order to comply with these new operational limits, Conectiv Energy restricted the output of the Deepwater Generating Station's Unit 1 and Unit 6/8. In 2006 and the first half

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of 2007, these restrictions resulted in operating losses of approximately $10,000 per operating day on Unit 6/8, primarily because of lost revenues due to reduced output, and to a lesser degree because of lost revenues related to capacity requirements of the PJM Interconnection, LLC (PJM). Since June 1, 2007, Deepwater Unit 6/8 can operate within the heat input limits set forth in the Title V Operating Permit without restricting output, because of technical improvements that partially corrected the inherent bias in the continuous emissions monitoring system that had caused recorded heat input to be higher than actual heat input. In order to comply with the heat input limit at Deepwater Unit 1, Conectiv Energy continues to restrict Unit 1 output. Beginning with the third quarter 2007, this Unit 1 restriction will result in semi-annual operating losses of approximately $500,000 in 2007 and 2008 due to penalties and lost revenues related to PJM capacity requirements. Beyond 2008, while penalties due to P JM capacity requirements are not expected, further operating losses due to lost revenues related to PJM capacity requirements may continue to be incurred. The operating losses due to reduced output on Unit 1 have been, and are expected to continue to be, insignificant. Conectiv Energy is challenging these heat input restrictions and other provisions of the Title V Operating Permit for Deepwater Generating Station in the New Jersey Office of Administrative Law (OAL). On October 2, 2007, the OAL issued a decision granting summary decision in favor of Conectiv Energy, finding that hourly heat input shall not be used as a condition or limit for Conectiv Energy's electric generating operations. On October 16, 2007, NJDEP requested that the commissioner of the NJDEP review and reject the OAL decision on an interlocutory basis. In its October 19, 2007 response, Conectiv Energy requested that the commissioner deny NJDEP's request for interlocutory review.

     On April 3, 2007, NJDEP issued an Administrative Order and Notice of Civil Administrative Penalty Assessment (the First Order) alleging that at Conectiv Energy's Deepwater Generating Station, the maximum gross heat input to Unit 1 exceeded the maximum allowable heat input in calendar year 2005 and the maximum gross heat input to Unit 6/8 exceeded the maximum allowable heat input in calendar years 2005 and 2006. The order required the cessation of operation of Units 1 and 6/8 above the alleged permitted heat input levels, assessed a penalty of approximately $1.1 million and requested that Conectiv Energy provide additional information about heat input to Units 1 and 6/8. Conectiv Energy provided NJDEP Units 1 and 6/8 calendar year 2004 heat input data on May 9, 2007, and calendar years 1995 to 2003 heat input data on July 10, 2007. On May 23, 2007, NJDEP issued a second Administrative Order and Notice of Civil Administrative Penalty Assessment (the Second Order) allegi ng that the maximum gross heat input to Units 1 and 6/8 exceeded the maximum allowable heat input in calendar year 2004. The Second Order required the cessation of operation of Units 1 and 6/8 above the alleged permitted heat input levels and assessed a penalty of $811,600. Conectiv Energy has requested a contested case hearing challenging the issuance of the First Order and the Second Order and moved for a stay of the orders pending resolution of the Title V Operating Permit contested case described above. Until the OAL decision discussed above is final, it will not have an impact on these enforcement cases.

     Carll's Corner Generating Station. On March 9, 2007, NJDEP issued an Administrative Order of Revocation and Notice of Civil Administrative Penalty Assessment alleging that emissions from Unit 1 at Conectiv Energy's Carll's Corner Generating Station, a nominal 43 megawatt peaking station, exceeded permitted particulate emissions levels during stack testing performed in June and November 2006. The order revoked Conectiv Energy's authority to operate Unit 1 effective April 21, 2007 and assessed a penalty of $110,000 for the alleged permit violations. As a result of the order, Conectiv Energy was not authorized to operate Carll's

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Corner Unit 1 until another stack test demonstrated compliance. On August 31, 2007, Conectiv Energy executed a settlement agreement with NJDEP, under which NJDEP determined the violation had been corrected, and Conectiv Energy agreed to operate in compliance with all applicable regulations and permits and paid a penalty of $55,000.

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 nonstrategic 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 exam team disallowed the qualification of the exchange under IRC Section 1031. In July 2006, Conectiv filed a protest of this disallowance to the IRS Office of Appeals.

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

     As of September 30, 2007, if the IRS fully prevails, the potential cash impact on PHI would be current income tax and interest payments of approximately $30.7 million and the earnings impact would be approximately $9.2 million in after-tax interest.

Federal Tax Treatment of Cross-border Leases

     PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which, as of September 30, 2007, had a book value of approximately $1.4 billion.

     On February 11, 2005, the Treasury Department and IRS issued Notice 2005-13 informing taxpayers that the IRS intends to challenge on various grounds the purported tax benefits claimed by taxpayers entering into certain sale-leaseback transactions with tax-indifferent parties (i.e., municipalities, tax-exempt and governmental entities) (the Notice). In addition, on June 29, 2005 the IRS published a Coordinated Issue Paper concerning the resolution of audit issues related to such transactions. PCI's cross-border energy leases are similar to those sale-leaseback transactions described in the Notice and the Coordinated Issue Paper.

     PCI's leases have been under examination by the IRS as part of the normal PHI tax audit. On June 9, 2006, the IRS issued its final RAR for its audit of PHI's 2001 and 2002 income tax returns. In the RAR, the IRS disallowed the tax benefits claimed by PHI with respect to certain of these leases for those years. The tax benefit claimed by PHI with respect to the leases under audit is approximately $60 million per year and from 2001 through September 30, 2007 were approximately $332 million. PHI has filed a protest against the IRS adjustments and the

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unresolved audit has been forwarded to the Appeals Office. The ultimate outcome of this issue is uncertain; however, if the IRS prevails, PHI would be subject to additional taxes, along with interest and possibly penalties on the additional taxes, which could have a material adverse effect on PHI's financial condition, results of operations, and cash flows. PHI believes that its tax position related to these transactions was appropriate based on applicable statutes, regulations and case law, and intends to contest the adjustments proposed by the IRS; however, there is no assurance that PHI's position will prevail.

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

IRS Mixed Service Cost Issue

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

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

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

     In February 2006, PHI paid approximately $121 million of taxes to cover the amount of taxes that management estimated to be payable based on the method of tax accounting that PHI, pursuant to the proposed regulations, has adopted on its 2005 tax return. However, if the IRS is

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successful in requiring Pepco, DPL and ACE to capitalize and depreciate construction costs that result in a tax and interest assessment greater than management's estimate of $121 million, PHI will be required to pay additional taxes and interest only to the extent these adjustments exceed the $121 million payment made in February 2006.

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

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

     As of September 30, 2007, Pepco Holdings and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, performance residual value, and other commitments and obligations. The fair value of these commitments and obligations was not required to be recorded in Pepco Holdings' Consolidated Balance Sheets; however, certain energy marketing obligations of Conectiv Energy were recorded. The commitments and obligations, in millions of dollars, were as follows:

	Guarantor
		PHI		DPL		ACE		Other		Total
Energy marketing obligations of Conectiv Energy (1)	$	192.2	$	-	$	-	$	-	$	192.2
Energy procurement obligations of Pepco Energy Services (1)		92.4		-		-		-		92.4
Guaranteed lease residual values (2)		-		2.7		3.0		.6		6.3
Other (3)		2.5		-		-		1.5		4.0
Total	$	287.1	$	2.7	$	3.0	$	2.1	$	294.9

1.	Pepco Holdings has contractual commitments for performance and related payments of Conectiv Energy and Pepco Energy Services to counterparties related to routine energy sales and procurement obligations, including requirements under BGS contracts entered into by Conectiv Energy with ACE.
2.	Subsidiaries of Pepco Holdings have guaranteed residual values in excess of fair value related to certain equipment and fleet vehicles held through lease agreements. As of September 30, 2007, obligations under the guarantees were approximately $6.3 million. Assets leased under agreements subject to residual value guarantees are typically for periods ranging from 2 years to 10 years. Historically, payments under the guarantees have not been made by the guarantor as, under normal conditions, the contract runs to full term at which time the residual value is minimal. As such, Pepco Holdings believes the likelihood of payment being required under the guarantee is remote.
3.	Other guarantees consist of:

· Pepco Holdings has guaranteed a subsidiary building lease of $2.5 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. As of September 30, 2007, the guarantees cover the remaining $1.5 million in rental obligations.

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     Pepco Holdings and certain of its subsidiaries have entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These indemnification agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Typically, claims may be made by third parties under these indemnification agreements over various periods of time depending on the nature of the claim. The maximum potential exposure under these indemnification agreements can range from a specified dollar amount to an unlimited amount depending on the nature of the claim and the particular transaction. The total maximum potential amount of future payments under these indemnification agreements is not estimable due to several factors, including uncertainty as to whether or when claims may be made under these indemn ities.

Dividends

     On October 25, 2007, Pepco Holdings' Board of Directors declared a dividend on common stock of 26 cents per share payable December 31, 2007, to shareholders of record on December 10, 2007.

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

     PHI accounts for its derivative activities in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), as amended by subsequent pronouncements. See "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, 2006, for a discussion of the accounting treatment of the derivatives used by PHI and its subsidiaries.

     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, 2007. 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 indicates the magnitude of the effective cash flow hedges by hedge type (i.e., other energy commodity and interest rate hedges), maximum term, and portion expected to be reclassified to earnings during the next 12 months.

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss As of September 30, 2007 (Millions of dollars)
Contracts		Accumulated OCI (Loss) After Tax (1)		Portion Expected to be Reclassified to Earnings during the Next 12 Months		Maximum    Term
Other Energy Commodity		$	(59.3)	$	(56.3)	51 months
Interest Rate			(29.6)		(3.3)	299 months
Total		$	(88.9)	$	(59.6)
(1)	Accumulated Other Comprehensive Loss as of September 30, 2007, includes $(8.8) million for an adjustment for minimum pension liability. This adjustment is not included in this table as it is not a cash flow hedge.

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     The following table shows, in millions of dollars, the net pre-tax gain or (loss) recognized in earnings for cash flow hedge ineffectiveness for the three and nine months ended September 30, 2007 and 2006, and where they were reported in PHI's Consolidated Statements of Earnings during the periods.

	Three Months Ended				Nine Months Ended
		2007		2006		2007		2006
Operating Revenue	$	(.4)	$	(.2)	$	(1.1)	$	(.2)
Fuel and Purchased Energy		(.2)		(.2)		(.2)		(.7)
Total	$	(.6)	$	(.4)	$	(1.3)	$	(.9)

     In connection with their energy commodity activities, the Competitive Energy businesses designate certain derivatives as fair value hedges. The net pre-tax gains (losses) recognized during the three and nine months ended September 30, 2007 and 2006, and included in the Consolidated Statements of Earnings for fair value hedges and the associated hedged items are shown in the following table, in millions of dollars for the three and nine months ended September 30, 2007 and 2006.

	Three Months Ended				Nine Months Ended
		2007		2006		2007		2006
Gain/(Loss) on Derivative Instruments	$	6.0	$	1.4	$	4.6	$	(4.4)
(Loss)/Gain on Hedged Items	$	(5.7)	$	(1.4)	$	(4.6)	$	4.4

     For the three and nine months ended September 30, 2007, $.2 million and $.1 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 months and nine months ended September 30, 2006, there were no forecasted hedged transactions or firm commitments deemed to be no longer probable.

     In connection with their other energy commodity activities, the Competitive Energy businesses hold certain derivatives that do not qualify as hedges. Under SFAS No. 133, these derivatives are marked-to-market through earnings with corresponding adjustments on the balance sheet. The pre-tax gains (losses) on these derivatives are included in "Competitive Energy Operating Revenues" and are summarized in the following table, in millions of dollars, for the three and nine months ended September 30, 2007 and 2006.

	Three Months Ended				Nine Months Ended
		2007		2006		2007		2006
Proprietary Trading (1)	$	-	$	-	$	-	$	-
Other Energy Commodity (2)		(11.8)		22.1		5.2		44.6
Total	$	(11.8)	$	22.1	$	5.2	$	44.6
(1) PHI discontinued its proprietary trading activity in 2003.
(2) Includes zero and $.5 million of ineffective fair value hedge gains for the             three and nine months ended September 30, 2007, respectively.

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POTOMAC ELECTRIC POWER COMPANY STATEMENTS OF EARNINGS (Unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
		2007		2006		2007		2006
		(Millions of dollars)
Operating Revenue	$	693.6	$	742.3	$	1,695.2	$	1,738.0
Operating Expenses
Fuel and purchased energy		404.0		462.4		964.8		1,022.7
Other operation and maintenance		78.4		70.0		220.7		214.3
Depreciation and amortization		33.0		42.1		116.9		123.6
Other taxes		80.0		76.0		220.3		206.1
Effect of settlement of Mirant bankruptcy claims		(33.4)		-		(33.4)		-
Gain on sale of assets		-		-		(.6)		-
Total Operating Expenses		562.0		650.5		1,488.7		1,566.7
Operating Income		131.6		91.8		206.5		171.3
Other Income (Expenses)
Interest and dividend income		2.8		1.2		3.6		4.2
Interest expense		(20.9)		(19.0)		(57.7)		(57.2)
Other income		2.6		2.6		9.1		10.6
Other expenses		(.2)		(.2)		(.4)		(.5)
Total Other Expenses		(15.7)		(15.4)		(45.4)		(42.9)
Income Before Income Tax Expense		115.9		76.4		161.1		128.4
Income Tax Expense		31.3		27.5		49.8		50.0
Net Income		84.6		48.9		111.3		78.4
Dividends on Redeemable Serial Preferred Stock		-		-		-		1.0
Earnings Available for Common Stock		84.6		48.9		111.3		77.4
Retained Earnings at Beginning of Period		555.5		538.8		559.7		574.3
Cumulative Effect Adjustment Related to   the Implementation of FIN 48		-		-		(1.9)		-
Dividends Paid to Parent		(45.0)		-		(74.0)		(64.0)
Retained Earnings at End of Period	$	595.1	$	587.7	$	595.1	$	587.7
The accompanying Notes are an integral part of these Financial Statements.
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POTOMAC ELECTRIC POWER COMPANY BALANCE SHEETS (Unaudited)
ASSETS		September 30, 2007		December 31, 2006
	(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$	10.5	$	12.4
Accounts receivable, less allowance for     uncollectible accounts of $10.7 million     and $17.4 million, respectively			413.8		318.3
Materials and supplies-at average cost			51.7		42.8
Prepayments of income taxes			16.8		66.5
Prepaid expenses and other			23.5		25.5
Total Current Assets			516.3		465.5
INVESTMENTS AND OTHER ASSETS
Regulatory assets			163.5		127.7
Prepaid pension expense			154.0		160.1
Investment in trust			31.0		29.0
Income taxes receivable			169.8		-
Restricted cash			416.7		-
Other			69.3		99.6
Total Investments and Other Assets			1,004.3		416.4
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			5,315.0		5,157.6
Accumulated depreciation			(2,251.2)		(2,162.5)
Net Property, Plant and Equipment			3,063.8		2,995.1
TOTAL ASSETS		$	4,584.4	$	3,877.0
The accompanying Notes are an integral part of these Financial Statements.
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POTOMAC ELECTRIC POWER COMPANY BALANCE SHEETS (Unaudited)
LIABILITIES AND SHAREHOLDER'S EQUITY		September 30, 2007		December 31, 2006
	(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt		$	194.1	$	67.1
Current maturities of long-term debt			253.0		210.0
Accounts payable and accrued liabilities			223.0		180.1
Accounts payable to associated companies			80.5		46.0
Capital lease obligations due within one year			5.7		5.5
Taxes accrued			34.3		72.8
Interest accrued			25.7		16.9
Liabilities and accrued interest related to uncertain tax positions			67.7		-
Other			90.8		157.3
Total Current Liabilities			974.8		755.7
DEFERRED CREDITS
Regulatory liabilities			545.4		146.8
Deferred income taxes			644.9		636.3
Investment tax credits			13.0		14.5
Other postretirement benefit obligation			67.0		69.3
Income taxes payable			127.4		-
Other			63.1		62.3
Total Deferred Credits			1,460.8		929.2
LONG-TERM LIABILITIES
Long-term debt			912.2		990.0
Capital lease obligations			108.1		110.9
Total Long-Term Liabilities			1,020.3		1,100.9
COMMITMENTS AND CONTINGENCIES (NOTE 4)
SHAREHOLDER'S EQUITY
Common stock, $.01 par value, authorized     200,000,000 shares, issued 100 shares			-		-
Premium on stock and other capital contributions			533.4		531.5
Retained earnings			595.1		559.7
Total Shareholder's Equity			1,128.5		1,091.2
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY		$	4,584.4	$	3,877.0
The accompanying Notes are an integral part of these Financial Statements.
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POTOMAC ELECTRIC POWER COMPANY STATEMENTS OF CASH FLOWS (Unaudited)
		Nine Months Ended September 30,
			2007		2006
	(Millions of dollars)
OPERATING ACTIVITIES
Net income		$	111.3	$	78.4
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization			116.9		123.6
Deferred income taxes			15.8		12.1
Effect of settlement of Mirant bankruptcy claims			(33.4)		-
Gain on sale of assets			(.6)		-
Proceeds from settlement of Mirant bankruptcy claims			507.2		70.0
Reimbursements to Mirant			(108.3)		-
Changes in restricted cash related to Mirant settlement			(416.7)		-
Changes in:
Accounts receivable			(116.4)		(40.6)
Regulatory assets and liabilities			(18.3)		(16.4)
Accounts payable and accrued liabilities			74.2		(4.2)
Interest and taxes accrued			40.2		(73.5)
Other changes in working capital			(15.1)		(18.5)
Net other operating			6.0		22.3
Net Cash From Operating Activities			162.8		153.2
INVESTING ACTIVITIES
Net investment in property, plant and equipment			(194.3)		(147.8)
Proceeds from settlement of Mirant bankruptcy claims representing   reimbursement for investment in property, plant and equipment			15.0		-
Net other investing activities			(2.4)		.3
Net Cash Used By Investing Activities			(181.7)		(147.5)
FINANCING ACTIVITIES
Dividends paid to Pepco Holdings			(74.0)		(64.0)
Dividends paid on preferred stock			-		(1.0)
Issuances of long-term debt			-		109.5
Reacquisition of long-term debt			(35.0)		(109.5)
Issuances of short-term debt, net			127.0		-
Redemption of preferred stock			-		(21.5)
Net other financing activities			(1.0)		(2.2)
Net Cash From (Used By) Financing Activities			17.0		(88.7)
Net Decrease in Cash and Cash Equivalents			(1.9)		(83.0)
Cash and Cash Equivalents at Beginning of Period			12.4		131.4
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	10.5	$	48.4
NONCASH ACTIVITIES
Asset retirement obligations associated with removal   costs transferred to regulatory liabilities		$	3.9	$	26.3
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for income taxes    (includes payments to PHI for Federal income taxes)		$	6.6	$	58.8
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). 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.

(2)  ACCOUNTING POLICY, PRONOUNCEMENTS, AND OTHER DISCLOSURES

Financial Statement Presentation

     Pepco's unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the 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, 2006. In the opinion of Pepco's management, the unaudited financial statements contain all adjustments (consisting of normal recurring accruals) necessary to present fairly Pepco's financial results for the interim periods presented herein. 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, 2007 may not be indicative of results that will be realized for the full year ending December 31, 2007 since the sales of electric energy are seasonal.

FIN 46R, "Consolidation of Variable Interest Entities"

     Due to a variable element in the pricing structure of Pepco's purchase power agreement with Panda-Brandywine, L.P. (Panda) entered into in 1991, pursuant to which Pepco is obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (Panda PPA), Pepco potentially assumes the variability in the operations of the plants related to the Panda PPA and therefore has a variable interest in the entity. In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R (revised December 2003), entitled "Consolidation of Variable Interest Entities" (FIN 46R), Pepco continued, during the third quarter of 2007, to conduct exhaustive efforts to obtain information from this entity, but was unable to obtain sufficient information to conduct the analysis required under FIN 46R to determine whether the entity was a variable interest entity or if Pepco was the

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primary beneficiary. As a result, Pepco has applied the scope exemption from the application of FIN 46R for enterprises that have conducted exhaustive efforts to obtain the necessary information, but have not been able to obtain such information.

     Power purchases related to the Panda PPA for the three months ended September 30, 2007 and 2006 were approximately $24 million and $23 million, respectively. Power purchases related to the Panda PPA for the nine months ended September 30, 2007 and 2006 were approximately $67 million and $60 million, respectively. For further information regarding the funding of power purchases under the Panda PPA see Note (4), Commitments and Contingencies, under "Final Resolution of Mirant Bankruptcy Matter."

     In April 2006, the FASB issued 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), which provides guidance on how to determine the variability to be considered in applying FIN 46(R). Pepco started applying the guidance in FSP FIN 46(R)-6 to new and modified arrangements effective July 1, 2006.

FIN 48, "Accounting for Uncertainty in Income Taxes"

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

     On May 2, 2007, the FASB issued FSP FIN 48-1, "Definition of Settlement in FASB Interpretation No. 48" (FIN 48-1), which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. Pepco applied the guidance of FIN 48-1 with its adoption of FIN 48 on January 1, 2007.

     Pepco adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, Pepco originally recorded a $6.8 million increase in retained earnings, representing the cumulative effect of the change in accounting principle. This adjustment was reflected for the first time in Pepco's Form 10-Q for the quarter ended March 31, 2007. Unrecognized tax benefits represent those tax benefits related to tax positions that have been taken or are expected to be taken in tax returns, including refund claims, that are not recognized in the financial statements because, in accordance with FIN 48, management has either measured the tax benefit at an amount less than the benefit claimed or expected to be claimed or concluded that it is not more likely than not that the tax position will be ultimately sustained. As of January 1, 2007, unrecognized tax benefits totaled $95.1 million. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. Unrecognized tax benefits at January 1, 2007, included $20.7 million that, if recognized, would lower the effective tax rate.

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     During the third quarter of 2007, PHI determined that an incorrect interest rate had been applied to certain tax overpayments due to Pepco. This error affected the interest accrued upon adoption of FIN 48 at January 1, 2007 and during the first and second quarters of 2007. To correct this error, the original Cumulative Effect Adjustment included in retained earnings related to the implementation of FIN 48 has been adjusted by an $8.7 million charge to reflect the accrual of interest at the proper interest rate. Further, the related interest accruals for each of the first two quarters of 2007 were overstated by $.5 million. The adjustment of $1.0 million to correct this overaccrual has been recorded in the third quarter of 2007.

     Pepco recognizes interest on under/over payments of income taxes and penalties in income tax expense. As of January 1, 2007, Pepco had accrued approximately $4.1 million of interest expense and penalties.

     Pepco, as a direct subsidiary of PHI, is included on PHI's consolidated Federal income tax return. Pepco's Federal income tax liabilities for all years through 2000 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where Pepco files state income tax returns (District of Columbia and Maryland), are the same as noted above.

     Total unrecognized tax benefits that may change over the next twelve months include the matter described in Note (4) Commitments and Contingencies under the heading "IRS Mixed Service Cost Issue."

     Included in the amount of unrecognized tax benefits at January 1, 2007 is a state of Maryland claim for refund in the amount of $31.8 million. Pepco filed an amended 2000 Maryland tax return on November 14, 2005 claiming the refund. The amended return claimed additional tax basis for purposes of computing the Maryland tax gain on the sale of Pepco's generating plants based on the tax benefit rule. This claim for refund was rejected by the state. Pepco filed an appeal by letter dated June 28, 2006. The Hearing Officer denied the appeal by a Notice of Final Determination dated February 22, 2007. Pepco petitioned Maryland Tax Court on March 22, 2007 for the refund. On August 1, 2007, Pepco entered into a settlement agreement with the Comptroller of Maryland on this matter. For further discussion, see "Maryland Income Tax Refund" below.

Components of Net Periodic Benefit Cost

     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, 2007, of $20.5 million includes $5.6 million for Pepco's allocated share. The remaining pension and other postretirement net periodic benefit cost is allocated to other PHI subsidiaries. PHI's pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2007, of $48.4 million includes $16.8 million for Pepco's allocated share. The remaining pension and other postretirement net periodic benefit cost is allocated to other PHI subsidiaries. PHI's pension and other postretirement net periodic benefit cost for the three months ended September 30, 2006, of $16.9 million includes $8.1 million for Pepco's allocated share. The remaining pension and other postretirement net periodic benefit cost is allocated t o other PHI subsidiaries. The pension net periodic benefit cost for the nine months ended September 30, 2006 of $50.7 million includes $24.1 million for Pepco's allocated share. The remaining pension and other postretirement net periodic benefit cost is allocated to other PHI subsidiaries.

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Reconciliation of Income Tax Expense

     A reconciliation of Pepco's income tax expense is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
	Amount	Rate	Amount	Rate	Amount	Rate	Amount	Rate
	(Millions of dollars)
Income Before Income Tax Expense	$115.9		$76.4		$161.1		$128.4
Income tax at Federal statutory rate	$  40.6	35%	$26.7	35%	$56.4	35%	$  44.9	35%
Increases (decreases) resulting from:
Depreciation	1.1	1	1.4	2	4.1	3	4.5	3
Maryland State refund, net of           Federal effect	(19.5)	(17)	-	-	(19.5)	(12)	-	-
Asset removal costs	(.5)	-	(.5)	(1)	(1.6)	(1)	(2.4)	(2)
State income taxes, net of          Federal effect	6.0	5	2.7	4	8.8	5	5.9	5
Software amortization	.9	1	.9	1	2.4	1	2.3	2
Tax credits	(.8)	(1)	(.5)	(1)	(1.8)	(1)	(1.5)	(1)
Change in estimates related to         prior year tax liabilities	.8	1	(2.3)	(3)	(.2)	-	(2.1)	(2)
Deferred tax adjustment	3.2	3	-	-	3.2	2	-	-
Other, net	(.5)	(1)	(.9)	(1)	(2.0)	(1)	(1.6)	(1)
Total Income Tax Expense	$  31.3	27%	$27.5	36%	$49.8	31%	$50.0	39%

     During the third quarter of 2007, Pepco completed an analysis of its deferred tax accounts as of December 31, 2006. As a result of this analysis, Pepco recorded a $3.2 million charge to income tax expense for the three months ended September 30, 2007, which is included in "Deferred tax adjustment" in the reconciliation provided above.

Maryland Income Tax Refund

     On August 1, 2007, Pepco entered into a settlement agreement with the Comptroller of Maryland pursuant to which Pepco received a refund of state income taxes paid in the amount of approximately $30 million, which was due to an increase in the tax basis of certain assets sold in 2000. The refund was recorded in the third quarter of 2007, net of Federal income taxes due on the refund and related professional fee expenses incurred in connection with the matter, and resulted in a $17.7 million increase to PHI's net income.

Amended and Restated Credit Facility

     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. The interest rate payable by each company on utilized funds is based on the prevailing prime rate or Eurodollar rate, plus a margin

56

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 use the facility to borrow funds for general corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties made by the borrower at the time the amended and restated credit agreement was entered into also must be true at the time the facility is utilized, and the borrower must be in compliance with specified covenants, including the financial covenant described below. However, a material adverse change in the borrower's business, property, and results of operations or financial condition subsequent to the entry into the amended and restated credit agreement is not a condition to the availability of credit under the facility. Among the covenants to which each of the companies is subject are (i) the requirement that each borrowing com pany maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the amended and restated credit agreement, which calculation excludes certain trust preferred securities and deferrable interest subordinated debt from the definition of total indebtedness (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than sales and dispositions permitted by the amended and restated credit agreement, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than liens permitted by the amended and restated credit agreement. The agreement does not contain any rating triggers.

Restricted Cash

     Restricted cash represents cash either held or pledged as collateral that is restricted from use for general corporate purposes and cash that is specifically segregated, based on management's intent, to fund the future above-market capacity and energy costs under the Panda PPA. Restricted cash is classified as current or non-current, consistent with the classification of the related liabilities.

Related Party Transactions

          PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including Pepco, pursuant to a service agreement. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries' share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to Pepco for the three months ended September 30, 2007 and 2006 were approximately $33.0 million and $24.2 million, respectively. PHI Service Company costs directly charged or allocated to Pepco for the nine

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months ended September 30, 2007 and 2006 were approximately $94.5 million and $84.7 million, respectively.

     Certain subsidiaries of Pepco Energy Services perform utility maintenance services, including services that are treated as capital costs, for Pepco. Amounts paid by Pepco to these companies for the three months ended September30, 2007 and 2006 were approximately $6.9 million and $3.2 million, respectively. Amounts paid by Pepco to these companies for the nine months ended September 30, 2007 and 2006 were approximately $22.9 million and $8.1 million, respectively.

     In addition to the transactions described above, Pepco's Statements of Earnings include the following related party transactions:

	For the Three Months Ended September  30,		For the Nine Months Ended September 30,
	2007	2006	2007	2006
Income (Expense)	(Millions of dollars)
Intercompany power purchases - Conectiv Energy Supply   (included in fuel and purchased energy)	$(19.2)	$(18.0)	$(48.9)	$(23.6)
Intercompany lease transactions related to computer services and   facility and building maintenance (included in other operation and   maintenance)	.1	(.5)	(.3)	(1.9)

     As of September 30, 2007 and December 31, 2006, Pepco had the following balances on its Balance Sheets due (to) from related parties:

	2007	2006
Asset (Liability)	(Millions of dollars)
Payable to Related Party (current)
PHI Service Company	$(17.8)	$    (.9)
PHI Parent	-	(5.0)
Conectiv Energy Supply	(5.3)	(4.8)
Pepco Energy Services (a)	(57.4)	(35.4)
The items listed above are included in the "Accounts payable to associated companies" balance on the Balance Sheet of $80.5 million and $46.0 million at September 30, 2007 and December 31, 2006, respectively.
Money Pool Balance with Pepco Holdings   (included in short-term debt in 2007 and cash and cash equivalents       in 2006 on the balance sheet)	$(43.1)	$     .4

(a) Pepco bills certain customers on behalf of Pepco Energy Services where those customers have elected to purchase electricity from Pepco Energy Services as their competitive supplier or where Pepco Energy Services has performed work primarily for certain government agencies under a General Services Administration area-wide agreement.

Reclassifications

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

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New Accounting Standards

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

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

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

     On June 28, 2006, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 06-3, "Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions" (EITF 06-3). EITF 06-3 provides guidance on an entity's disclosure of its accounting policy regarding the gross or net presentation of certain taxes and provides that if taxes included in gross revenues are significant, a company should disclose the amount of such taxes for each period for which an income statement is presented (i.e., both interim and annual periods). Taxes within the scope of EITF 06-3 are those that are imposed on and concurrent with a specific revenue-producing transaction. Taxes assessed on an entity's activities over a period of time are not within the scope of EITF 06-3. Pepco implemented EITF 06-3 during the first quarter of 2007. Taxes included in Pepco's gross revenues were $67.9 million and $64.5 million for the three months ended September 30, 20 07 and 2006, respectively and $184.5 million and $172.8 million for the nine months ended September 30, 2007 and 2006, respectively.

     SFAS No. 157, "Fair Value Measurements"

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

     SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (year ending December 31, 2008 for Pepco). Pepco is currently in the process of evaluating the impact that SFAS No. 157 will have on its overall financial condition, results of operations, and cash flows.

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

     On September 8, 2006, the FASB issued FSP American Institute of Certified Public Accountants Industry Audit Guide, Audits of Airlines--"Accounting for Planned Major Maintenance Activities" (FSP AUG AIR-1), which prohibits the use of the accrue-in-advance

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method of accounting for planned major maintenance activities in annual and interim financial reporting periods for all industries. FSP AUG AIR-1 is effective the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for Pepco). Implementation of FSP AUG AIR-1 did not have a material impact on Pepco's overall financial condition, results of operations, or cash flows.

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

     On September 20, 2006, the FASB ratified EITF Issue No. 06-5, "Accounting for Purchases of Life Insurance -- Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of Life Insurance" (EITF 06-5) which provides guidance on whether an entity should consider the contractual ability to surrender all of the individual-life policies (or certificates under a group life policy) together when determining the amount that could be realized in accordance with FTB 85-4, and whether a guarantee of the additional value associated with the group life policy affects that determination. EITF 06-5 provides that a policyholder should (i) determine the amount that could be realized under the insurance contract assuming the surrender of an individual-life by individual-life policy (or certificate by certificate in a group policy) and (ii) not discount the cash surrender value component of the amount that could be realized when c ontractual restrictions on the ability to surrender a policy exist unless contractual limitations prescribe that the cash surrender value component of the amount that could be realized is a fixed amount, in which case the amount that could be realized should be discounted in accordance with Accounting Principles Board of the American Institute of Certified Public Accountants Opinion 21. EITF 06-5 is effective for fiscal years beginning after December 15, 2006 (year ending December 31, 2007 for Pepco). Implementation of EITF 06-5 did not have a material impact on Pepco's overall financial condition, results of operations, cash flows, or footnote disclosure requirements.

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

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

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

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

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

(3)  SEGMENT INFORMATION

     In accordance with Statement of Financial Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information," Pepco has one segment, its regulated utility business.

(4)  COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Final Resolution of Mirant Bankruptcy Matter

     In 2000, Pepco sold substantially all of its electricity generating assets to Mirant Corporation (formerly Southern Energy, Inc.) and certain of its subsidiaries. In July 2003, Mirant and certain of its subsidiaries filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas (the Bankruptcy Court). In December 2005, the Bankruptcy Court approved the Plan of Reorganization (the Reorganization Plan) of Mirant and the Mirant business emerged from bankruptcy in January 2006, as a new corporation of the same name (together with its predecessors, Mirant).

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

     Power Purchase Agreement

     The Panda PPA obligates Pepco to purchase from Panda 230 megawatts of energy and capacity annually through 2021. At the time of the sale of Pepco's generating assets to Mirant, the purchase price of the energy and capacity under the Panda PPA was, and since that time has continued to be, substantially in excess of the market price. As a part of the Asset Purchase and Sale Agreement, Pepco entered into a "back-to-back" arrangement with Mirant. Under this arrangement, Mirant was obligated through 2021 to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the Panda PPA at a price equal to Pepco's purchase price from Panda (the PPA-Related Obligations).

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     The SMECO Agreement

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

     Settlement Agreements with Mirant

     In May 2006, Pepco, PHI, and certain affiliated companies entered into a Settlement Agreement and Release (the Settlement Agreement) with Mirant, which settled all outstanding issues between the parties arising from or related to the Mirant bankruptcy, as more fully described below. Separately, Mirant and SMECO entered into a Settlement Agreement and Release (the SMECO Settlement Agreement), which provides that Mirant will assume, rather than reject, the SMECO Agreement. This assumption ensures that Pepco will not incur liability to SMECO as the guarantor of the SMECO Agreement due to the rejection of the SMECO Agreement, although Pepco will continue to guarantee to SMECO the future performance of Mirant under the SMECO Agreement.

     In August 2006, the Bankruptcy Court issued an order approving the Settlement Agreement and the SMECO Settlement Agreement. This order was appealed to the United States District Court for the Northern District of Texas (the District Court) by certain holders of Mirant bankruptcy claims who had objected to approval of the Settlement Agreement and the SMECO Settlement Agreement before the Bankruptcy Court. In December 2006, the District Court issued an order affirming the Bankruptcy Court's order approving the Settlement Agreement and the SMECO Settlement Agreement. In January 2007, the parties that appealed the Bankruptcy Court's order filed a notice of appeal of the District Court's order with the United States Court of Appeals for the Fifth Circuit (the Fifth Circuit). On August 8, 2007, the Fifth Circuit, on the basis of a settlement between Mirant and the objecting creditors, issued an order dismissing the appeal with prejudice.

     Under the terms of the Settlement Agreement, Mirant assumed the Asset Purchase and Sale Agreement, except for the PPA-Related Obligations, and Pepco was to receive $520 million, consisting of (i) $450 million in damages as compensation from Mirant for rejecting the PPA-Related Obligations and (ii) $70 million in settlement of other Pepco damage claims against the Mirant bankruptcy estate. To implement the settlement, the following transactions occurred.

· Pepco received from Mirant shares of Mirant stock with an estimated value of $520.0 million, which were liquidated, resulting in net cash proceeds of $522.2 million, after transaction costs.

· Pepco reimbursed Mirant $2.2 million, representing the excess of the amount of the net proceeds of $522.2 million over the settlement amount of $520.0 million.

· Pepco reimbursed Mirant $70.0 million for the amount previously received by Pepco from Mirant in August 2006, which became due in accordance with the

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	terms of the Settlement Agreement as a result of its approval by the Bankruptcy Court. At the time of receipt, Pepco did not recognize any portion of the payment in earnings pending the appeal of the Bankruptcy Court order.
·	Pepco reimbursed Mirant $36.1 million, representing the net above-market costs paid by Mirant under the Panda PPA "back-to-back" arrangement during the period from June 1, 2006, the date the parties entered into the Settlement Agreement, to August 8, 2007, the date the objecting creditors' appeal was dismissed by the Fifth Circuit.

     In addition, under the Settlement Agreement, all pending appeals, adversary actions and other contested matters between Pepco and Mirant were dismissed with prejudice and each party released the other from any and all claims relating to the Mirant bankruptcy.

     Pepco intends to use the $413.9 million of the settlement payment (the $450 million portion, less the $36.1 million that Pepco has reimbursed to Mirant), plus interest earned, to pay for future above-market capacity and energy purchases under the Panda PPA over the remaining life of the Panda PPA through 2021. The $413.9 million is being accounted for as non-current restricted cash, and a corresponding non-current regulatory liability has been recorded, based on Pepco's expectation that both the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC) will issue orders directing Pepco to use the proceeds, and any earnings on the proceeds, solely to offset the future above-market costs. Management intends to seek these orders from the DCPSC and the MPSC in the fourth quarter of 2007.

     Of the $70.0 million received in settlement of other Pepco damage claims, $33.4 million has been recorded as a reduction of operating expenses, $21.0 million has been recorded as a reduction in a net pre-petition receivable claim from Mirant, $15.0 million has been recorded as a reduction in the capitalized costs of certain property plant and equipment and the remaining $.6 million has been recorded as a liability to reimburse SMECO for certain legal costs associated with the settlement.

Rate Proceedings

     In electric service distribution base rate cases filed by Pepco in the District of Columbia and Maryland, Pepco proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers. Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the approved revenue-per-customer amount. The BSA will increase rates if actual distribution revenues fall below the level approved by the applicable commission and will decrease rates if actual distribution revenues are above the approved level. The result will be that, over time, Pepco would collect its authorized revenues for distribution deliveries. As a consequence, a BSA "decouples" revenue from unit sales consumption and ties the growth in revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable utility distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers' delivery bills, and (iv) removes any disincentives for Pepco to promote energy efficiency programs for its customers, because it breaks the link between overall sales volumes and

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delivery revenues. The status of the BSA proposals in each of the jurisdictions is described below in discussion of the respective base rate proceedings.

     District of Columbia

     On December 12, 2006, Pepco submitted an application to the DCPSC to increase electric distribution base rates, including a proposed BSA. The application to the DCPSC requested an annual increase of approximately $46.2 million or an overall increase of 13.5%, reflecting a proposed return on equity (ROE) of 10.75%. In the alternative, the application requested an annual increase is $50.5 million or an overall increase of 14.8%, reflecting an ROE of 11.00%, if the BSA is not approved. Hearings were held in the case in June 2007. A DCPSC decision is expected in the fourth quarter of 2007.

     Maryland

     On July 19, 2007, the MPSC issued an order in the electric service distribution rate case filed by Pepco. The order approved a temporary 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 order provided that the rate increase is effective as of June 16, 2007, and will remain in effect for an initial period of nine months from the date of the order (or until April 19, 2008). The temporary rate is subject to a Phase II proceeding in which the MPSC will consider the results of an audits of Pepco's cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rate is required. The MPSC approved a proposed BSA.

Divestiture Cases

     District of Columbia

     Final briefs on Pepco's District of Columbia divestiture proceeds sharing application were filed with the DCPSC in July 2002 following an evidentiary hearing in June 2002. That application was filed to implement a provision of Pepco's DCPSC-approved divestiture settlement that provided for a sharing of any net proceeds from the sale of Pepco's generation-related assets. One of the principal issues in the case is whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code and its implementing regulations. As of September 30, 2007, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6.5 million and $5.8 million, respectively.

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

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($5.8 million as of September 30, 2007), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($4.2 million as of September 30, 2007) in each case as those balances exist as of the later of the date a DCPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the DCPSC order becomes operative.

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

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

     Maryland

    Pepco filed its divestiture proceeds plan application with the MPSC in April 2001. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that has been raised in the District of Columbia case. See the discussion above under "Divestiture Cases -- District of Columbia." As of September 30, 2007, the Maryland allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $9.1 million and $10.4 million, respectively. Other issues deal with the treatment of certain costs as deductions from the gross proceeds of the divestiture. In November 2003, the Hearing Examiner in the Maryland proceeding issued a proposed order with respect to the application that concluded that Pepco's Maryland divestiture settlement agreement provided for a sharing between Pepco and customers of the EDIT and ADITC associated with the sold assets. Pepco believes that such a sharing would violate the normalization rules (discussed ab ove) 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, 2007), 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, 2007), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($7.5 million as of September 30, 2007), in each case as those balances exist as of the

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later of the date a MPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the MPSC order becomes operative. The Hearing Examiner decided all other issues in favor of Pepco, except for the determination that only one-half of the severance payments that Pepco included in its calculation of corporate reorganization costs should be deducted from the sales proceeds before sharing of the net gain between Pepco and customers. Pepco filed a letter with the MPSC in January 2006, in which it has reiterated that the MPSC should continue to defer any decision on the ADITC and EDIT issues until the IRS issues final regulations or states that its regulations project related to this issue will be terminated without the issuance of any regulations.

     In December 2003, Pepco appealed the Hearing Examiner's decision to the MPSC as it relates to the treatment of EDIT and ADITC and corporate reorganization costs. The MPSC has not issued any ruling on the appeal and Pepco does not believe that it will do so until action is taken by the IRS as described above. However, depending on the ultimate outcome of this proceeding, Pepco could be required to share with its customers approximately 50 percent of the EDIT and ADITC balances described above in addition to the additional gain-sharing payments relating to the disallowed severance payments (which Pepco is not contesting). Such additional payments would be charged to expense in the quarter and year in which a final decision is rendered and could have a material adverse effect on results of operations for those periods. However, neither PHI nor Pepco believes that additional gain-sharing payments, if any, or the ADITC-related payments to the IRS, if required, would have a mat erial adverse impact on its financial position or cash flows.

General Litigation

     During 1993, Pepco was served with Amended Complaints filed in the state Circuit Courts of Prince George's County, Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated proceedings known as "In re: Personal Injury Asbestos Case." Pepco and other corporate entities were brought into these cases on a theory of premises liability. Under this theory, the plaintiffs argued that Pepco was negligent in not providing a safe work 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, 2007, 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 have been tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement. Under the terms of the Settlement Agreement, Mirant has agreed to assume this contractual obligation. For a description of the Settlement Agreement, see the discussion of the resolution of the Mirant bankruptcy matter above.

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

Environmental Litigation

     Pepco is subject to regulation by various Federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition, Federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. Pepco may incur costs to clean up currently 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.

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

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

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

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remediation costs exceed the Bankruptcy Funds available. The Utility PRPs also will be liable for EPA costs associated with overseeing the monitoring and operation of the site remedy after the remedy construction is certified to be complete and also the cost of performing the "5 year" review of site conditions required by the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Any Bankruptcy Funds not spent on the remedy may be used to cover the Utility PRPs' liabilities for future costs. No parties are released from potential liability for damages to natural resources.

     As of September 30, 2007, Pepco had accrued $1.7 million to meet its liability for a remedy at the Metal Bank/Cottman Avenue site. While final costs to Pepco of the settlement have not been determined, Pepco believes that its liability at this site will not have a material adverse effect on its financial position, results of operations or cash flows.

IRS Mixed Service Cost Issue

     During 2001, Pepco changed its method of accounting with respect to capitalizable construction costs for income tax purposes. The change allowed 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 $94 million, primarily attributable to its 2001 tax returns.

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

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

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

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DELMARVA POWER & LIGHT COMPANY STATEMENTS OF EARNINGS (Unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
		2007		2006		2007		2006
		(Millions of dollars)
Operating Revenue
Electric	$	356.1	$	360.9	$	929.8	$	908.8
Natural Gas		43.3		34.0		221.2		193.9
Total Operating Revenue		399.4		394.9		1,151.0		1,102.7
Operating Expenses
Fuel and purchased energy		253.3		272.0		656.6		639.2
Gas purchased		33.9		26.1		171.0		153.8
Other operation and maintenance		52.0		48.0		151.4		138.6
Depreciation and amortization		18.6		19.2		55.9		57.4
Other taxes		9.9		9.5		27.7		28.3
Gain on sale of assets		(.4)		-		(1.0)		(1.1)
Total Operating Expenses		367.3		374.8		1,061.6		1,016.2
Operating Income		32.1		20.1		89.4		86.5
Other Income (Expenses)
Interest and dividend income		.1		.3		.8		.8
Interest expense		(11.2)		(10.8)		(32.6)		(30.1)
Other income		.9		1.9		2.0		5.6
Other expense		-		(1.1)		-		(3.3)
Total Other Expenses		(10.2)		(9.7)		(29.8)		(27.0)
Income Before Income Tax Expense		21.9		10.4		59.6		59.5
Income Tax Expense		10.8		5.1		23.9		26.5
Net Income		11.1		5.3		35.7		33.0
Dividends on Redeemable Serial Preferred Stock		-		.2		-		.6
Earnings Available for Common Stock		11.1		5.1		35.7		32.4
Retained Earnings at Beginning of Period		423.5		412.0		426.4		399.7
Dividends Paid to Parent		-		-		(27.0)		(15.0)
Preferred Stock Redemption		-		-		(.6)		-
Cumulative Effect Adjustment Related   to the Implementation of FIN 48		-		-		.1		-
Retained Earnings at End of Period	$	434.6	$	417.1	$	434.6	$	417.1
The accompanying Notes are an integral part of these Financial Statements.
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DELMARVA POWER & LIGHT COMPANY BALANCE SHEETS (Unaudited)
ASSETS		September 30, 2007		December 31, 2006
	(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$	6.1	$	8.2
Restricted cash			2.9		-
Accounts receivable, less allowance for     uncollectible accounts of $8.6 million     and $7.8 million, respectively			208.6		193.7
Fuel, materials and supplies-at average cost			49.3		40.1
Prepayments of income taxes			48.7		46.3
Prepaid expenses and other			17.0		18.4
Total Current Assets			332.6		306.7
INVESTMENTS AND OTHER ASSETS
Goodwill			8.0		48.5
Regulatory assets			217.8		187.2
Prepaid pension expense			176.5		171.8
Other			32.4		18.4
Total Investments and Other Assets			434.7		425.9
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			2,591.1		2,512.8
Accumulated depreciation			(827.8)		(794.2)
Net Property, Plant and Equipment			1,763.3		1,718.6
TOTAL ASSETS		$	2,530.6	$	2,451.2
The accompanying Notes are an integral part of these Financial Statements.
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DELMARVA POWER & LIGHT COMPANY BALANCE SHEETS (Unaudited)
LIABILITIES AND SHAREHOLDER'S EQUITY		September 30, 2007		December 31, 2006
	(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt		$	288.5	$	195.9
Current maturities of long-term debt			22.6		64.7
Accounts payable and accrued liabilities			94.0		95.0
Accounts payable to associated companies			35.8		9.6
Taxes accrued			5.4		3.2
Interest accrued			8.7		6.2
Liabilities and accrued interest related to uncertain tax positions			34.1		-
Other			61.7		58.4
Total Current Liabilities			550.8		433.0
DEFERRED CREDITS
Regulatory liabilities			283.7		272.4
Deferred income taxes			394.3		424.1
Investment tax credits			9.3		9.9
Above-market purchased energy contracts and other      electric restructuring liabilities			21.7		23.5
Other			65.3		49.2
Total Deferred Credits			774.3		779.1
LONG-TERM LIABILITIES
Long-term debt			529.3		551.8
COMMITMENTS AND CONTINGENCIES (NOTE 4)
REDEEMABLE SERIAL PREFERRED STOCK			-		18.2
SHAREHOLDER'S EQUITY
Common stock, $2.25 par value, authorized     1,000,000 shares, issued 1,000 shares			-		-
Premium on stock and other capital contributions			241.6		242.7
Retained earnings			434.6		426.4
Total Shareholder's Equity			676.2		669.1
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY		$	2,530.6	$	2,451.2
The accompanying Notes are an integral part of these Financial Statements.
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DELMARVA POWER & LIGHT COMPANY STATEMENTS OF CASH FLOWS (Unaudited)
		Nine Months Ended September 30,
			2007		2006
	(Millions of dollars)
OPERATING ACTIVITIES
Net income		$	35.7	$	33.0
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization			55.9		57.4
Gain on sale of assets			(1.0)		(1.1)
Investment tax credit adjustments			(.6)		(.6)
Deferred income taxes			8.9		10.1
Changes in:
Accounts receivable			(15.1)		(16.9)
Regulatory assets and liabilities			1.7		(9.3)
Accounts payable and accrued liabilities			23.5		(11.2)
Interest and taxes accrued			(.5)		(59.6)
Other changes in working capital			(5.3)		.8
Net other operating			.6		(3.2)
Net Cash From (Used By) Operating Activities			103.8		(.6)
INVESTING ACTIVITIES
Net investment in property, plant and equipment			(92.4)		(104.2)
Changes in restricted cash			(2.9)		-
Proceeds from sale of property			.4		2.2
Net other investing activities			(.4)		(1.5)
Net Cash Used By Investing Activities			(95.3)		(103.5)
FINANCING ACTIVITIES
Dividends paid to Pepco Holdings			(27.0)		(15.0)
Dividends paid on preferred stock			-		(.6)
Reacquisition of long-term debt			(64.7)		(2.9)
Issuances of short-term debt, net			92.6		113.3
Redemption of preferred stock			(18.2)		-
Net other financing activities			6.7		7.3
Net Cash (Used By) From Financing Activities			(10.6)		102.1
Net Decrease in Cash and Cash Equivalents			(2.1)		(2.0)
Cash and Cash Equivalents at Beginning of Period			8.2		7.4
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	6.1	$	5.4
NONCASH ACTIVITIES
Asset retirement obligations associated with removal   costs transferred to regulatory liabilities		$	4.7	$	47.8
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for income taxes    (includes payments to PHI for Federal income taxes)		$	4.0	$	44.7
The accompanying Notes are an integral part of these Financial Statements.
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NOTES TO FINANCIAL STATEMENTS

DELMARVA POWER & LIGHT COMPANY

(1)  ORGANIZATION

     Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and Virginia, and provides gas distribution service in northern Delaware. As discussed in Note (4), "Commitments and Contingencies -- DPL Sale of Virginia Operations," DPL in June 2007 entered into an agreement to sell substantially all of its Virginia electric service operations. Additionally, DPL supplies electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier. The regulatory term for this service varies by jurisdiction as follows:

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

     In this Form 10-Q, DPL also refers to this supply service in each of its jurisdictions generally as Default Electricity Supply.

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

(2)  ACCOUNTING POLICY, PRONOUNCEMENTS, AND OTHER DISCLOSURES

Financial Statement Presentation

     DPL's unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the 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, 2006. In the opinion of DPL's management, the unaudited financial statements contain all adjustments (consisting of normal recurring accruals) necessary to present fairly DPL's financial results for the interim periods presented herein. 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 Septemb er 30, 2007 may not be indicative of results that will be realized for the full year ending December 31, 2007 since the sales of electric energy are seasonal.

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Adjustment to DPL's Previously Reported Maryland SOS Expenses

     In 2004, DPL implemented deferral accounting for Maryland SOS customers. In the third quarter of 2006, DPL recorded an adjustment to correct the fuel and purchased energy expense deferral amount that had been recognized on Maryland SOS customers since its implementation in the third quarter of 2004. This adjustment reduced DPL's earnings for the three and nine months ended September 30, 2006 by $2.4 million.

FIN 48, "Accounting for Uncertainty in Income Taxes"

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

     On May 2, 2007, the FASB issued FASB Staff Position (FSP) FIN 48-1, "Definition of Settlement in FASB Interpretation No. 48" (FIN 48-1), which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. DPL applied the guidance of FIN 48-1 with its adoption of FIN 48 on January 1, 2007.

     DPL adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, DPL recorded a $.1 million increase in retained earnings, representing the cumulative effect of the change in accounting principle. This adjustment was reflected for the first time in DPL's Form 10-Q for the quarter ended March 31, 2007. Unrecognized tax benefits represent those tax benefits related to tax positions that have been taken or are expected to be taken in tax returns, including refund claims, that are not recognized in the financial statements because, in accordance with FIN 48, management has either measured the tax benefit at an amount less than the benefit claimed or expected to be claimed or concluded that it is not more likely than not that the tax position will be ultimately sustained. As of January 1, 2007, unrecognized tax benefits totaled $43.2 million. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. Unrecognized tax benefits at January 1, 2007, included $6.7 million that, if recognized, would lower the effective tax rate.

     DPL recognizes interest on under/over payments of income taxes and penalties in income tax expense. As of January 1, 2007, DPL had accrued approximately $9.8 million of interest expense and penalties.

     DPL, as an indirect subsidiary of PHI, is included on PHI's consolidated Federal tax return. DPL's Federal income tax liabilities for all years through 1999 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks

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from subsequent years. The open tax years for the significant states where DPL files state income tax returns (Maryland, Delaware, and Virginia), are the same as noted above.

     Total unrecognized tax benefits that may change over the next twelve months include the matter described in Note (4) Commitments and Contingencies under the heading "IRS Mixed Service Cost Issue."

Components of Net Periodic Benefit Cost

     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, 2007, of $20.5 million includes $.6 million for DPL's allocated share. The remaining pension and other postretirement net periodic benefit cost is allocated to other PHI subsidiaries. PHI's pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2007, of $48.4 million includes $1.8 million for DPL's allocated share. The remaining pension and other postretirement net periodic benefit cost is allocated to other PHI subsidiaries. PHI's pension and other postretirement net periodic benefit cost for the three months ended September 30, 2006, of $16.9 million includes $.1 million for DPL's allocated share. The remaining pension and other postretirement net periodic benefit cost is allocated to other PHI subsidiaries. The pension net periodic benefit cost for the nine months ended September 30, 2006 of $50.7 million includes $.5 million for DPL's allocated share. The remaining pension and other postretirement net periodic benefit cost is allocated to other PHI subsidiaries.

Reconciliation of Income Tax Expense

     A reconciliation of DPL's income tax expense is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
	Amount	Rate	Amount	Rate	Amount	Rate	Amount	Rate
	(Millions of dollars)
Income Before Income Tax Expense	$21.9		$10.4		$59.6		$59.5
Income tax at Federal statutory rate	$  7.7	35%	$  3.6	35%	$20.9	35%	$20.8	35%
Increases (decreases) resulting from:
State income taxes, net         of Federal effect	1.1	5	.5	5	3.0	5	4.0	7
Depreciation	.6	3	.5	5	1.8	3	1.3	2
Tax credits	(.2)	(1)	(.2)	(2)	(.6)	(1)	(.6)	(1)
Adjustment to prior years' tax	.2	1	-	-	.2	-	-	-
Change in estimates related to         prior year tax liabilities	.3	1	.6	5	(2.5)	(4)	1.8	3
Deferred tax adjustment	1.2	5	-	-	1.2	2	-	-
Other, net	(.1)	-	.1	1	(.1)	-	(.8)	(1)
Total Income Tax Expense	$ 10.8	49%	$ 5.1	49%	$23.9	40%	$26.5	45%

     During the third quarter of 2007, DPL completed an analysis of its deferred tax accounts as of December 31, 2006. As a result of this analysis, DPL recorded a $1.2 million charge to income tax expense for the three months ended September 30, 2007, which is included in "Deferred tax adjustment" in the reconciliation provided above.

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Resolution of Uncertain Tax Positions

     In June 2007, DPL entered into a settlement with the State of Delaware related to the allocation of a gain on the sale of real property that occurred in 2001, pursuant to which DPL made a cash payment of approximately $12 million, consisting of $7.4 million in tax and $4.6 million in interest. DPL's tax reserves for this issue exceed by $2.8 million the settlement amount. The excess reserves were credited to DPL's income tax expense in the second quarter. Because the matter involved a Conectiv tax contingency that existed at the time of the acquisition of Conectiv in August 2002, an additional adjustment of $1.9 million has been recorded in Corporate and Other to eliminate a portion of the tax benefit recorded by DPL.

Goodwill

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

Balance,  December 31, 2006	$  48.5
Less:  Third quarter adjustment to transfer recoverable portion of goodwill to regulatory asset	(40.5)
Balance,  September 30, 2007	$    8.0

     On July 19, 2007, the Maryland PSC issued an order which provided for the recovery of a portion of DPL's goodwill through February 2018. As a result of this order, $40.5 million in DPL goodwill has been transferred to a regulatory asset, which will be amortized over that same period.

Amended and Restated Credit Facility

     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. 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 indebted ness 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 use the facility to borrow funds for general corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties made by the borrower at the

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time the amended and restated credit agreement was entered into also must be true at the time the facility is utilized, and the borrower must be in compliance with specified covenants, including the financial covenant described below. However, a material adverse change in the borrower's business, property, and results of operations or financial condition subsequent to the entry into the amended and restated credit agreement is not a condition to the availability of credit under the facility. Among the covenants to which each of the companies is subject are (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the amended and restated credit agreement, which calculation excludes certain trust preferred securities and deferrable interest subordinated debt from the definition of total indebtedness (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispo sitions of assets, other than sales and dispositions permitted by the amended and restated credit agreement, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than liens permitted by the amended and restated credit agreement. The agreement does not include any rating triggers.

Related Party Transactions

     PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including DPL, pursuant to a service agreement. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries' share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to DPL for the three months ended September 30, 2007 and 2006 were approximately $27.2 million and $23.0 million, respectively. PHI Service Company costs directly charged or allocated to DPL for the nine months ended September 30, 2007 and 2006 were approximately $79.9 million and $73.7 million, respectively.

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

	For the Three Months Ended September 30,		For the Nine Months Ended September 30,
	2007	2006	2007	2006
Income (Expense)	(Millions of dollars)
Full Requirements Contract with Conectiv Energy Supply for power,         capacity and ancillary services to service POLR (included in fuel         and purchased energy expenses)	$      -	$      -	$      -	$(122.2)
SOS agreement with Conectiv Energy Supply (included in fuel and        purchased energy)	(73.8)	(93.6)	(209.3)	(152.9)
Intercompany lease transactions (included in electric revenue)	1.8	2.2	5.6	6.3
Transcompany pipeline gas sales with Conectiv Energy Supply        (included in gas revenue)	.5	.7	2.2	2.2
Transcompany pipeline gas purchase with Conectiv Energy Supply        (included in gas purchased)	-	(.4)	(1.5)	(1.6)

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     As of September 30, 2007 and December 31, 2006, DPL had the following balances on its Balance Sheets due from/(to) related parties:

		2007		2006
Asset (Liability)		(Millions of dollars)
Receivable from Related Party (current)
PHI Service Company	$	-	$	46.4
Payable to Related Party (current)
PHI Service Company		(11.7)		-
PHI Parent		-		(24.7)
Conectiv Energy Supply		(18.6)		(24.6)
Pepco Energy Services		(6.4)		(7.7)
The items listed above are included in the "Accounts payable to associated companies" balance on the Balance Sheet of $35.8 million and $9.6 million at September 30, 2007 and December 31, 2006, respectively.
Money Pool Balance with Pepco Holdings   (included in short-term debt on balance sheet)	$	(48.4)	$	-

New Accounting Standards

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

     On June 28, 2006, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 06-3, "Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions" (EITF 06-3). EITF 06-3 provides guidance on an entity's disclosure of its accounting policy regarding the gross or net presentation of certain taxes and provides that if taxes included in gross revenues are significant, a company should disclose the amount of such taxes for each period for which an income statement is presented (i.e., both interim and annual periods). Taxes within the scope of EITF 06-3 are those that are imposed on and concurrent with a specific revenue-producing transaction. Taxes assessed on an entity's activities over a period of time are not within the scope of EITF 06-3. DPL implemented EITF 06-3 during the first quarter of 2007. Taxes included in DPL's gross revenues were $3.7 million and $4.2 million for the three months ended September 30, 2007 and 20 06, respectively and $9.9 million and $11.2 million for the nine months ended September 30, 2007 and 2006, respectively.

     SFAS No. 157, "Fair Value Measurements"

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

     SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (year ending December 31, 2008 for DPL). DPL is currently in the process of evaluating the impact that SFAS No. 157 will have on its overall financial condition, results of operations, and cash flows.

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

     On September 8, 2006, the FASB issued FSP American Institute of Certified Public Accountants Industry Audit Guide, Audits of Airlines--"Accounting for Planned Major Maintenance Activities" (FSP AUG AIR-1), which prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods for all industries. FSP AUG AIR-1 is effective the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for DPL). Implementation of FSP AUG AIR-1 did not have a material impact on DPL's overall financial condition, results of operations, or cash flows.

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

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

     SFAS No. 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company's choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. SFAS No. 159 does not eliminate disclosure requirements included in other accounting standards.

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

(3) SEGMENT INFORMATION

     In accordance with Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information," DPL has one segment, its regulated utility business.

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(4)  COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Rate Proceedings

     Delaware

     On August 31, 2006, DPL submitted its 2006 Gas Cost Rate (GCR) filing to the Delaware Public Service Commission (DPSC), which permits DPL to recover gas procurement costs through customer rates. In October 2006, the DPSC issued an initial order approving the proposed rates, which became effective November 1, 2006, subject to refund pending final DPSC approval after evidentiary hearings. In February 2007, DPL submitted an additional filing to the DPSC that proposed an additional 4.3% decrease in the GCR effective April 1, 2007, in compliance with its gas service tariff and to ensure collections are more aligned with expenses. In March 2007, the DPSC approved the rate decrease, subject to refund pending final DPSC approval after evidentiary hearings. On July 17, 2007, the DPSC granted final approval for the GCR, as filed.

     On September 4, 2007, DPL submitted its 2007 GCR filing to the DPSC. On September 18, 2007, the DPSC issued an initial order approving a 5.7% decrease in the level of the GCR, which will become effective November 1, 2007, subject to refund and pending final DPSC approval after evidentiary hearings.

     Maryland

     In the electric service distribution base rate case filed by DPL in Maryland, DPL proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers. Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the approved revenue-per-customer amount. The BSA will increase rates if actual distribution revenues fall below the level approved by the Maryland Public Service Commission (MPSC) and will decrease rates if actual distribution revenues are above the approved level. The result will be that, over time, DPL would collect its authorized revenues for distribution deliveries. As a consequence, a BSA "decouples" revenue from unit sales consumption and ties the growth in revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weath er 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.

     On July 19, 2007, the MPSC issued an order in the electric service distribution rate case. The order approved a temporary annual increase in distribution rates of approximately $14.9 million (including a decrease in annual depreciation expense of approximately $0.9 million). The approved distribution rate reflects a return on equity (ROE) of 10.0%. The order provided that the rate increase is effective as of June 16, 2007, and will remain in effect for an initial period of nine months from the date of the order (or until April 19, 2008). The temporary rate is subject to a Phase II proceeding in which the MPSC will consider the results of an audit of DPL's cost

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allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rate is required. The MPSC approved the proposed BSA.

Default Electricity Supply Proceedings

     Virginia

     As discussed below under the heading "DPL Sale of Virginia Operations," DPL has entered into an agreement to sell substantially all of its Virginia electric service operations.

     On April 2, 2007, DPL filed an application with Virginia State Corporation Commission (VSCC) to adjust its Default Service rates covering the period June 1, 2007 to May 31, 2008. The proposed rates for this service during the first month of this period (June 2007) are based on the fuel proxy rate calculation described below. The proposed rates for the remaining 11 months of the period (July 1, 2007 to May 31, 2008) reflect the fuel cost of Default Service supply based upon the results of the competitive bidding wholesale procurement process. The calculations in the application result in a rate decrease of approximately $1.7 million for the period, June 1 to June 30, 2007, and an increase of approximately $4.2 million for the period, July 1, 2007 to May 31, 2008, resulting in an overall annual rate increase of approximately $2.5 million.

     The "fuel proxy rate calculation" was established under a Memorandum of Agreement (MOA) that DPL entered into with the staff of the VSCC in connection with the approval of DPL's divestiture of its generation assets in 2000, and provides for the calculation of the fuel rate portion of Default Service rates that reflect an approximation of the fuel costs that DPL would have incurred had it retained its generating assets. Since June 1, 2006, use of the proxy rate calculation has resulted in DPL being unable to recover fully its cost of providing Default Service. The April 2007 rate application reflects DPL's position that the use of the fuel proxy rate calculation to establish Default Service rates terminated on July 1, 2007, and effective that date, it should be permitted to charge customers market based fuel costs. However, pursuant to an order dated June 8, 2007, the VSCC denied the July 1, 2007 rate increase, based on its conclusion that the MOA's provisions relating to f uel costs did not end effective June 30, 2007. As a result of this decision, DPL under-recovered its cost of providing Default Service by approximately $1.9 million between June 1, 2007 and the September 30, 2007 expiration of the Default Service contract. Any further under-recovery will be determined by the difference between the fuel proxy rate calculation and market rates for the fuel portion of Default Service and the timing of completion of the sale of DPL's Virginia electric operations as described below under the heading "DPL Sale of Virginia Operations." A fixed price, partial hedge has been purchased for the period through December 31, 2007, which should substantially limit DPL's exposure to market price fluctuations during that period.

     DPL filed a complaint for a declaratory order and preliminary injunctive relief with the U.S. District Court for the Eastern District of Virginia (the Virginia District Court). On July 23, 2007, the Virginia District Court dismissed the complaint and denied injunctive relief, finding that the court lacked subject matter jurisdiction and stating that even if it had subject matter jurisdiction, it would abstain from exercising that jurisdiction to allow the Supreme Court of Virginia to consider the issues upon which the complaint was based.

     DPL currently is pursuing relief in both state and federal courts: On July 31, 2007, DPL filed a notice of appeal of the VSCC's orders with the Supreme Court of Virginia; and on August 31, 2007, DPL filed an appeal from the Virginia District Court's order with the U. S. Court of

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Appeals for the Fourth Circuit. The sale of DPL's Virginia electric operations as described below under the heading "DPL Sale of Virginia Operations" is not contingent upon resolution of any of the matters that are at issue in these proceedings. If the sale of the Virginia electric operations is completed, the effect, if any, on these proceedings is not determinable at this time.

DPL Sale of Virginia Operations

     On June 13, 2007, DPL entered into agreements (i) to sell to A&N Electric Cooperative (A&N) all of its assets principally related to DPL's business of distributing retail electric services to customers located on the Eastern Shore of Virginia, including real and personal property, accounts receivable and customer deposits, for a purchase price of approximately $39.8 million, subject to closing adjustments, and (ii) to sell to Old Dominion Electric Cooperative (ODEC) certain assets principally related to DPL's provision of wholesale electric transmission services located on the Eastern Shore of Virginia, for a purchase price of approximately $4.8 million, subject to closing adjustments. Each of A&N and ODEC will assume certain post-closing liabilities and unknown pre-closing liabilities related to the respective assets they are purchasing (including, in the A&N transaction, most environmental liabilities), except that DPL will remain liable for unknown pre-closing liabilities if they become known within six months after the respective closing dates. On October 9, 2007, FERC granted approval of an interconnection agreement and a facilities agreement needed for the completion of the ODEC transaction. On October 19, 2007, the VSCC issued an order approving both transactions. Northern Virginia Electric Cooperative (NOVAC) intervened in the VSCC proceedings, opposing the DPL sales to A&N and ODEC. NOVAC may file a petition for reconsideration within 20 days of the order. They also may appeal the VSCC order within 30 days. If filed, this would be considered an appeal "of right," which means the Virginia Supreme Court must hear the appeal. DPL expects the transactions to close during the fourth quarter of 2007, contingent upon the receipt of required final, non-appealable regulatory approvals. These sales, if completed, will not result in a material financial gain or loss to DPL.

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.

     Cambridge, Maryland Site. In July 2004, DPL entered into an administrative consent order with the Maryland Department of the Environment (MDE) to perform a Remedial Investigation/Feasibility Study (RI/FS) to further identify the extent of soil, sediment and ground and surface water contamination related to former manufactured gas plant (MGP) operations at a Cambridge, Maryland site on DPL-owned property and to investigate the extent of MGP contamination on adjacent property. The MDE has approved the RI and DPL submitted a final FS to MDE on February 15, 2007. The costs of cleanup (as determined by the RI/FS and subsequent negotiations with MDE) are anticipated to be approximately $3.5 million. The

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remedial action will include dredging activities within Cambridge Creek, which are expected to take place as early as November 2007, and soil excavation on DPL's and adjacent property as early as January 2008. The final cleanup costs will include protective measures to control contaminant migration during the dredging activities and improvements to the existing shoreline dock.

     Metal Bank/Cottman Avenue Site. In the early 1970s, DPL sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a nonaffiliated company. In December 1987, DPL was notified by the United States Environmental Protection Agency (EPA) that it, along with a number of other utilities and non-utilities, was a potentially responsible party in connection with the PCB contamination at the site. In 1999, DPL entered into a de minimis settlement with EPA and paid approximately $107,000 to resolve its liability for cleanup costs at the Metal Bank/Cottman Avenue site. The de minimis settlement did not resolve DPL's responsibility for natural resource damages, if any, at the site. DPL believes that any liability for natural resource damages at this site will not have a material adverse effect on its financial position, results of operations or cash f lows.

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 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 $62 million, primarily attributable to its 2001 tax returns.

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

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

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

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF EARNINGS (Unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
		2007		2006		2007		2006
		(Millions of dollars)
Operating Revenue	$	504.7	$	479.7	$	1,181.2	$	1,080.2
Operating Expenses
Fuel and purchased energy		349.1		321.5		815.9		723.0
Other operation and maintenance		41.7		35.0		118.6		109.9
Depreciation and amortization		21.0		34.6		55.5		94.2
Other taxes		7.8		7.5		17.5		17.9
Deferred electric service costs		29.1		19.2		45.1		7.5
Gain on sale of assets		-		-		(.4)		-
Total Operating Expenses		448.7		417.8		1,052.2		952.5
Operating Income		56.0		61.9		129.0		127.7
Other Income (Expenses)
Interest and dividend income		.3		1.0		1.1		1.3
Interest expense		(16.2)		(16.3)		(48.4)		(47.5)
Other income		1.4		1.1		3.8		3.9
Other expense		-		-		-		(3.1)
Total Other Expenses		(14.5)		(14.2)		(43.5)		(45.4)
Income Before Income Tax Expense		41.5		47.7		85.5		82.3
Income Tax Expense		15.0		18.5		32.2		28.0
Income from Continuing Operations		26.5		29.2		53.3		54.3
Discontinued Operations (Note 5)
Income from operations (net of taxes of     zero and $.4 million for the three     months ended September 30, 2007 and 2006,     respectively, and $.1 million and $1.5 million     for the nine months ended September 30, 2007     and 2006, respectively)		-		.7		.1		2.3
Net Income		26.5		29.9		53.4		56.6
Dividends on Redeemable Serial Preferred Stock		.1		.1		.2		.2
Earnings Available for Common Stock		26.4		29.8		53.2		56.4
Retained Earnings at Beginning of Period		128.8		186.2		132.0		178.6
Dividends Paid to Parent		(20.0)		(75.0)		(50.0)		(94.0)
Retained Earnings at End of Period	$	135.2	$	141.0	$	135.2	$	141.0
The accompanying Notes are an integral part of these Consolidated Financial Statements.
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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)
ASSETS		September 30, 2007		December 31, 2006
	(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$	5.0	$	5.5
Restricted cash			9.2		9.0
Accounts receivable, less allowance for     uncollectible accounts of $5.3 million     and $5.5 million, respectively			227.0		163.0
Fuel, materials and supplies-at average cost			13.7		12.6
Prepayments of income taxes			75.8		54.5
Prepaid expenses and other			33.2		16.9
B.L. England assets held for sale			-		14.4
Total Current Assets			363.9		275.9
INVESTMENTS AND OTHER ASSETS
Regulatory assets			830.2		857.5
Restricted funds held by trustee			9.6		17.5
Prepaid pension expense			9.2		11.7
Other			40.0		19.5
B.L. England assets held for sale			-		79.2
Total Investments and Other Assets			889.0		985.4
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			2,021.3		1,942.9
Accumulated depreciation			(625.6)		(599.1)
Net Property, Plant and Equipment			1,395.7		1,343.8
TOTAL ASSETS		$	2,648.6	$	2,605.1
The accompanying Notes are an integral part of these Consolidated Financial Statements.
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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)
LIABILITIES AND SHAREHOLDER'S EQUITY		September 30, 2007		December 31, 2006
	(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt		$	97.2	$	23.8
Current maturities of long-term debt			80.7		45.9
Accounts payable and accrued liabilities			130.7		110.3
Accounts payable to associated companies			21.3		27.3
Taxes accrued			2.8		8.5
Interest accrued			11.4		13.7
Liabilities and accrued interest related to uncertain tax positions			26.6		-
Other			36.9		38.1
Liabilities associated with B.L. England assets held for sale			-		.9
Total Current Liabilities			407.6		268.5
DEFERRED CREDITS
Regulatory liabilities			389.7		360.2
Deferred income taxes			440.2		441.0
Investment tax credits			8.2		14.9
Other postretirement benefit obligation			40.0		27.1
Other			27.4		14.0
Liabilities associated with B.L. England assets held for sale			-		78.6
Total Deferred Credits			905.5		935.8
LONG-TERM LIABILITIES
Long-term debt			415.7		465.7
Transition Bonds issued by ACE Funding			442.8		464.4
Total Long-Term Liabilities			858.5		930.1
COMMITMENTS AND CONTINGENCIES (NOTE 4)
REDEEMABLE SERIAL PREFERRED STOCK			6.2		6.2
SHAREHOLDER'S EQUITY
Common stock, $3.00 par value, authorized     25,000,000 shares, 8,546,017 shares outstanding			25.6		25.6
Premium on stock and other capital contributions			310.0		306.9
Retained earnings			135.2		132.0
Total Shareholder's Equity			470.8		464.5
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY		$	2,648.6	$	2,605.1
The accompanying Notes are an integral part of these Consolidated Financial Statements.
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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
		Nine Months Ended September 30,
			2007		2006
	(Millions of dollars)
OPERATING ACTIVITIES
Net income		$	53.4	$	56.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization			55.5		94.2
Deferred income taxes			23.3		(12.2)
Gain on sale of assets			(.4)		-
Changes in:
Accounts receivable			(63.5)		7.4
Accounts payable and accrued liabilities			12.0		(97.3)
Regulatory assets and liabilities			34.5		18.7
Interest and taxes accrued			(.5)		(52.1)
Other changes in working capital			(20.9)		(6.6)
Net other operating			(4.8)		3.8
Net Cash From Operating Activities			88.6		12.5
INVESTING ACTIVITIES
Net investment in property, plant and equipment			(91.0)		(83.9)
Proceeds from sale of assets			9.0		177.0
Net other investing activities			7.1		(2.6)
Net Cash (Used By) From Investing Activities			(74.9)		90.5
FINANCING ACTIVITIES
Dividends paid to Pepco Holdings			(50.0)		(94.0)
Dividends paid on preferred stock			(.2)		(.2)
Issuances of long-term debt			-		105.0
Reacquisition of long-term debt			(36.9)		(85.2)
Issuances of short-term debt, net			73.4		-
Net other financing activities			(.5)		3.2
Net Cash Used By Financing Activities			(14.2)		(71.2)
Net (Decrease) Increase in Cash and Cash Equivalents			(.5)		31.8
Cash and Cash Equivalents at Beginning of Period			5.5		8.2
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	5.0	$	40.0
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)		$	33.0	$	64.7
The accompanying Notes are an integral part of these Consolidated Financial Statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ATLANTIC CITY ELECTRIC COMPANY

(1) ORGANIZATION

     Atlantic City Electric Company (ACE) is engaged in the generation, transmission and distribution of electricity in southern New Jersey. ACE 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 is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI). Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between PHI and ACE and certain activities of ACE are subject to the regulatory oversight of the Federal Energy Regulatory Commission under PUHCA 2005.

     In addition to its electricity transmission and distribution operations, during 2006 ACE owned a 2.47% undivided interest in the Keystone electric generating facility, a 3.83% undivided interest in the Conemaugh electric generating facility (with a combined generating capacity of 108 megawatts), and also owned the B.L. England electric generating facility (with a generating capacity of 447 megawatts). On September 1, 2006, ACE sold its interests in the Keystone and Conemaugh generating facilities and on February 8, 2007, ACE completed the sale of the B.L. England generating facility.

(2)  ACCOUNTING POLICY, PRONOUNCEMENTS, AND OTHER DISCLOSURES

Financial Statement Presentation

     ACE's unaudited consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the 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, 2006. In the opinion of ACE's management, the unaudited consolidated financial statements contain all adjustments (consisting of normal recurring accruals) necessary to present fairly ACE's financial results for the interim periods presented herein. 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, 2007 may not be indicative of results that will be realized for the full year ending December 31, 2007 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), ACE continued, during the third quarter of 2007, to conduct exhaustive efforts to obtain information from these entities, but was unable to obtain sufficient information to conduct the analysis required under FIN 46R to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, ACE has applied the scope exemption from the application of FIN 46R for enterprises that have conducted exhaustive efforts to obtain the necessary information, but have not been able to obtain such information.

     Net power purchase activities with the counterparties to the NUGs for the three months ended September 30, 2007 and 2006 were approximately $88 million and $86 million, respectively, of which $79 million and $76 million, respectively, related to power purchases under the NUGs. Net power purchase activities with the counterparties to the NUGs for the nine months ended September 30, 2007 and 2006 were approximately $248 million and $250 million, respectively, of which $222 million and $220 million, respectively, related to power purchases under the NUGs. ACE does not have exposure to loss under the PPA agreements since cost recovery will be achieved from its customers through regulated rates.

     In April 2006, the FASB issued 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), which provides guidance on how to determine the variability to be considered in applying FIN 46(R). ACE started applying the guidance in FSP FIN 46(R)-6 to new and modified arrangements effective July 1, 2006.

FIN 48, "Accounting for Uncertainty in Income Taxes"

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

     On May 2, 2007, the FASB issued FSP FIN 48-1, "Definition of Settlement in FASB Interpretation No. 48" (FIN 48-1), which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. ACE applied the guidance of FIN 48-1 with its adoption of FIN 48 on January 1, 2007.

     ACE adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, ACE had an immaterial adjustment to its retained earnings, representing the cumulative effect of the change in accounting principle. This adjustment was reflected for the first time in ACE's Form 10-Q for the quarter ended March 31, 2007. Unrecognized tax benefits represent those tax benefits related to tax positions that have been taken or are expected to be taken in tax returns, including refund claims, that are not recognized in the financial statements

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because, in accordance with FIN 48, management has either measured the tax benefit at an amount less than the benefit claimed or expected to be claimed or concluded that it is not more likely than not that the tax position will be ultimately sustained. As of January 1, 2007, unrecognized tax benefits totaled $28.4 million. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. Unrecognized tax benefits at January 1, 2007, included no amounts that, if recognized, would lower the effective tax rate.

     ACE recognizes interest on under/over payments of income taxes and penalties in income tax expense. As of January 1, 2007, ACE had accrued approximately $3.4 million of interest expense and penalties.

     ACE, as an indirect subsidiary of PHI, is included on PHI's consolidated Federal tax return. ACE's Federal income tax liabilities for all years through 1999 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where ACE files state income tax returns (New Jersey and Pennsylvania), are the same as noted above.

     Total unrecognized tax benefits that may change over the next twelve months include the matter described in Note (4), "Commitments and Contingencies" under the heading "IRS Mixed Service Cost Issue."

Components of Net Periodic Benefit Cost

     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, 2007, of $20.5 million includes $2.9 million for ACE's allocated share. The remaining pension and other postretirement net periodic benefit cost is allocated to other PHI subsidiaries. PHI's pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2007, of $48.4 million includes $8.7 million for ACE's allocated share. The remaining pension and other postretirement net periodic benefit cost is allocated to other PHI subsidiaries. PHI's pension and other postretirement net periodic benefit cost for the three months ended September 30, 2006, of $16.9 million includes $3.6 million for ACE's allocated share. The remaining pension and other postretirement net periodic benefit cost is allocated to other P HI subsidiaries. The pension net periodic benefit cost for the nine months ended September 30, 2006 of $50.7 million includes $10.7 million for ACE's allocated share. The remaining pension and other postretirement net periodic benefit cost is allocated to other PHI subsidiaries.

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Reconciliation of Consolidated Income Tax Expense

     A reconciliation of ACE's consolidated income tax expense is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
	Amount	Rate	Amount	Rate	Amount	Rate	Amount	Rate
	(Millions of dollars)
Income Before Income Tax Expense     and Discontinued Operations	$41.5		$47.7		$85.5		$82.3
Income tax at Federal statutory rate	$14.5	35%	$16.7	35%	$29.9	35%	$28.8	35%
Increases (decreases) resulting from:
State income taxes,         net of Federal effect	2.8	6	3.1	6	5.7	7	5.7	7
Depreciation	.1	-	.2	1	.3	1	.3	-
Tax credits	(.3)	(1)	(.3)	(1)	(1.0)	(1)	(1.0)	(1)
Adjustment to prior years' tax	(1.3)	(3)	(.5)	(1)	(1.5)	(2)	(2.1)	(3)
Change in estimates related to         prior year tax liabilities	(.1)	-	(.6)	(1)	(.5)	(1)	(3.6)	(4)
Deferred tax adjustment	(.6)	(1)	-	-	(.6)	(1)	-	-
Other	(.1)	-	(.1)	-	(.1)	-	(.1)	-
Total Consolidated Income   Tax Expense	$15.0	36%	$18.5	39%	$32.2	38%	$28.0	34%

     During the third quarter of 2007, ACE completed an analysis of its deferred tax accounts as of December 31, 2006. As a result of this analysis, ACE recorded a $0.6 million credit to income tax expense for the three months ended September 30, 2007, which is included in "Deferred tax adjustment" in the reconciliation provided above.

Amended and Restated Credit Facility

     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. 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 indebted ness 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 use the facility to borrow funds for general corporate purposes and issue letters of credit. In order for a borrower to use the facility, certain representations and warranties made by the borrower at the

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time the amended and restated credit agreement was entered into also must be true at the time the facility is utilized, and the borrower must be in compliance with specified covenants, including the financial covenant described below. However, a material adverse change in the borrower's business, property, and results of operations or financial condition subsequent to the entry into the amended and restated credit agreement is not a condition to the availability of credit under the facility. Among the covenants to which each of the companies is subject are (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the amended and restated credit agreement, which calculation excludes certain trust preferred securities and deferrable interest subordinated debt from the definition of total indebtedness (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than sales and dispositions permitted by the amended and restated credit agreement, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than liens permitted by the amended and restated credit agreement. The agreement does not include any rating triggers.

Debt

     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%.

Related Party Transactions

     PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including ACE, pursuant to a service agreement. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries' share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to ACE for the three months ended September 30, 2007 and 2006 were approximately $20.6 million and $17.5 million, respectively. PHI Service Company costs directly charged or allocated to ACE for the nine months ended September 30, 2007 and 2006 were approximately $60 million and $58.9 million, respectively.

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

	For the Three Months Ended September 30		For the Nine Months Ended September 30,
	2007	2006	2007	2006
Income (Expense)	(Millions of dollars)
Purchased power from Conectiv Energy Supply (included in   fuel and purchased energy expenses)	$(36.1)	$(32.5)	$(77.1)	$(71.6)
Meter reading services provided by Millennium Account   Services, LLC (b)	(1.0)	(.9)	(2.9)	(2.8)
Intercompany lease transactions (b)	(.3)	(.1)	(1.0)	(.1)
Intercompany use revenue (a)	.4	.4	1.4	.9
Intercompany use expense (a)	(.4)	(.4)	(1.4)	(.8)

     (a) Included in operating revenue

     (b) Included in operation and maintenance

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     As of September 30, 2007 and December 31, 2006, ACE had the following balances on its Consolidated Balance Sheets due (to) from related parties:

		2007		2006
Asset (Liability)		(Millions of dollars)
Receivable from Related Party (current)
PHI Parent	$	-	$	8.4
Payable to Related Party (current)
PHI Service Company		(10.2)		(28.7)
Conectiv Energy Supply		(10.0)		(6.3)
DPL		(.4)		(.3)
The items listed above are included in the "Accounts payable to associated companies" balance on the Consolidated Balance Sheet of $21.3 million and $27.3 million at September 30, 2007 and December 31, 2006, respectively.

New Accounting Standards

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

     On June 28, 2006, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 06-3, "Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions" (EITF 06-3). EITF 06-3 provides guidance on an entity's disclosure of its accounting policy regarding the gross or net presentation of certain taxes and provides that if taxes included in gross revenues are significant, a company should disclose the amount of such taxes for each period for which an income statement is presented (i.e., both interim and annual periods). Taxes within the scope of EITF 06-3 are those that are imposed on and concurrent with a specific revenue-producing transaction. Taxes assessed on an entity's activities over a period of time are not within the scope of EITF 06-3. ACE implemented EITF 06-3 during the first quarter of 2007. Taxes included in ACE's gross revenues were $7.1 million and $7.2 million for the three months ended September 30, 2007 and 200 6, respectively and $17.6 million and $17.3 million for the nine months ended September 30, 2007 and 2006, respectively.

     SFAS No. 157, "Fair Value Measurements"

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

     SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (year ending December 31, 2008 for ACE). ACE is currently in the process of evaluating the impact that SFAS No. 157 will have on its overall financial condition, results of operations, and cash flows.

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

     On September 8, 2006, the FASB issued FSP American Institute of Certified Public Accountants Industry Audit Guide, Audits of Airlines--"Accounting for Planned Major Maintenance Activities" (FSP AUG AIR-1), which prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods for all industries. FSP AUG AIR-1 is effective the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for ACE). Implementation of FSP AUG AIR-1 did not have a material impact on ACE's overall financial condition, results of operations, or cash flows.

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

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

     SFAS No. 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company's choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. SFAS No. 159 does not eliminate disclosure requirements included in other accounting standards.

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

(3) SEGMENT INFORMATION

     In accordance with Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information," ACE has one segment, its regulated utility business.

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(4)  COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Rate Proceedings

     New Jersey

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

     ACE projects that, as of September 30, 2007 (based upon actual data through August 2007), the NGC, which is intended primarily to recover the above-market component of payments made by ACE under non-utility generation contracts and stranded costs associated with those commitments, will have an over-recovery balance of $216.2 million. The filing proposes that the NGC balance, including interest, be amortized and returned to ACE customers over a four-year period, beginning October 1, 2007.

     ACE also projects that, as of September 30, 2007 (based upon actual data through August 2007), the SBC, which is intended to allow ACE to recover certain costs involved with various NJBPU-mandated social programs, will have an under-recovery of approximately $19.6 million, primarily due to increased costs associated with funding the New Jersey Clean Energy Program. In addition, ACE has requested an increase to the SBC to reflect the funding levels approved by the NJBPU of $20.4 million for the period October 1, 2007 through September 30, 2008, which will require the SBC to recover a total of $40 million for the period of October 1, 2007 to September 30, 2008 (based upon actual data through August 2007).

     The net impact of the proposed adjustments to the NGC and the SBC, including associated changes in sales and use tax, is an overall rate decrease of approximately $129.9 million for the period October 1, 2007 through September 30, 2008 (based upon actual data through August 2007). The proposed adjustments and the corresponding changes in customer rates are subject to the approval of the NJBPU. If approved and implemented, ACE anticipates that the revised rates will remain in effect until September 30, 2008, subject to an annual true-up and change each year thereafter. The proposed adjustments and the corresponding changes in customer rates remain under review by the NJBPU and have not yet been implemented.

ACE Restructuring Deferral Proceeding

     Pursuant to orders issued by the NJBPU under the New Jersey Electric Discount and Energy Competition Act (EDECA), beginning August 1, 1999, ACE was obligated to provide BGS to retail electricity customers in its service territory who did not elect to purchase electricity from a competitive supplier. For the period August 1, 1999 through July 31, 2003, ACE's aggregate costs that it was allowed to recover from customers exceeded its aggregate revenues from supplying BGS. These under-recovered costs were partially offset by a $59.3 million deferred energy cost liability existing as of July 31, 1999 (LEAC Liability) related to ACE's Levelized

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Energy Adjustment Clause and ACE's Demand Side Management Programs. ACE established a regulatory asset in an amount equal to the balance of under-recovered costs.

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

     In July 2004, the NJBPU issued a final order in the restructuring deferral proceeding confirming a July 2003 summary order, which (i) permitted ACE to begin collecting a portion of the deferred costs and reset rates to recover on-going costs incurred as a result of EDECA, (ii) approved the recovery of $125 million of the deferred balance over a ten-year amortization period beginning August 1, 2003, (iii) transferred to ACE's then pending base rate case for further consideration approximately $25.4 million of the deferred balance (the base rate case ended in a settlement approved by the NJBPU in May 2005, the result of which is that any net rate impact from the deferral account recoveries and credits in future years will depend in part on whether rates associated with other deferred accounts considered in the case continue to generate over-collections relative to costs), and (iv) estimated the overall deferral balance as of July 31, 2003 at $195 million, of whic h $44.6 million was disallowed recovery by ACE. Although ACE believes the record does not justify the level of disallowance imposed by the NJBPU in the final order, the $44.6 million of disallowed incurred costs were reserved during the years 1999 through 2003 (primarily 2003) through charges to earnings, primarily in the operating expense line item "deferred electric service costs," with a corresponding reduction in the regulatory asset balance sheet account. In 2005, an additional $1.2 million in interest on the disallowed amount was identified and reserved by ACE. In August 2004, ACE filed a notice of appeal with respect to the July 2004 final order with the Appellate Division of the Superior Court of New Jersey (the Appellate Division), which hears appeals of the decisions of New Jersey administrative agencies, including the NJBPU. On August 9, 2007, the Appellate Division, citing deference to the factual and policy findings of the NJBPU, affirmed the NJBPU's decision in its entirety, rejecting challenges from ACE and the Division of Rate Counsel. On September 10, 2007, ACE filed an application for certification to the New Jersey Supreme Court. Though ACE continues to believe that the position it took before the Appellate Division is correct, there is no assurance that the New Jersey Supreme Court will agree to hear this discretionary appeal.

Divestiture Case

     New Jersey

     In connection with the divestiture by ACE of its nuclear generating assets, the NJBPU in July 2000 preliminarily determined that the amount of stranded costs associated with the divested assets that ACE could recover from ratepayers should be reduced by approximately $94.8 million, consisting of $54.1 million of accumulated deferred Federal income taxes (ADFIT) associated with accelerated depreciation on the divested nuclear assets, and $40.7 million of current tax loss from selling the assets at a price below the tax basis.

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     The $54.1 million in deferred taxes associated with the divested assets' accelerated depreciation, however, is subject to the normalization rules. Due to uncertainty under Federal tax law regarding whether the sharing of Federal income tax benefits associated with the divested assets, including ADFIT related to accelerated depreciation, with ACE's customers would violate the normalization rules, ACE submitted a request to the Internal Revenue Service (IRS) for a Private Letter Ruling (PLR) to clarify the applicable law. The NJBPU delayed its final determination of the amount of recoverable stranded costs until after the receipt of the PLR.

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

     On June 9, 2006, ACE submitted a letter to the NJBPU, requesting that the NJBPU conduct proceedings to finalize the determination of the stranded costs associated with the sale of ACE's nuclear assets in accordance with the PLR. In the absence of an NJBPU action regarding ACE's request, on June 22, 2007, ACE filed a motion requesting that the NJBPU issue an order finalizing the determination of such stranded costs in accordance with the PLR. On October 24, 2007, the NJBPU approved a stipulation resolving the ADFIT issue and issued a clarifying order, which concludes that the $94.8 million in stranded cost reduction, including the $54.1 million in ADFIT, does not violate the IRS normalization rules. In explaining this result, the NJBPU stated that (i) its earlier orders determining ACE's recoverable stranded costs "net of tax" did not cause ADFIT associated with certain divested nuclear assets to reduce stranded costs otherwise recoverable from ACE's ratepaye rs, and (ii) because the Market Transition Charge-Tax component of the stranded cost recovery was intended by the NJBPU to gross-up "net of tax" stranded costs, thereby ensuring and establishing that the ADFIT balance was not flowed through to ratepayers, the normalization rules were not violated.

ACE Sale of B.L. England Generating Facility

     On February 8, 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy Investments, LLC, for which it received proceeds of approximately $9 million, after giving effect to certain post-closing adjustments. At the time of the sale, RC Cape May and ACE agreed to submit to arbitration the issue of whether RC Cape May, under the terms of the purchase agreement, must pay to ACE an additional $3.1 million as part of the purchase price. Arbitration hearings were held October 15 through 17, 2007. An oral argument is scheduled for January 15, 2008, and a decision by the arbitrators is expected in February 2008. As part of the sale, RC Cape May assumed certain liabilities associated with the B.L. England generating station, including substantially all environmental liabilities.

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

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arbitrator rule that the TSA has terminated, the outcome of this matter is uncertain. ACE notified RC Cape May of its intent to participate in the pending arbitration.

     The sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized. ACE anticipates that approximately $9 million to $10 million of additional regulatory assets related to B.L. England may, subject to NJBPU approval, be eligible for recovery as stranded costs. Approximately $47 million in emission allowance credits associated with B. L. England were monetized for the benefit of ACE's ratepayers pursuant to the NJBPU order approving the sale. Net proceeds from the sale of the plant and monetization of the emission allowance credits, will be credited to ACE's ratepayers in accordance with the requirements of EDECA and NJBPU orders. The appropriate mechanism for crediting the net proceeds from the sale of the plant and the monetized emission allowance credits to ratepayers is being determined in a Phase II proceeding which is currently pending before the NJBPU.

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 respective cost of service for ratemaking purposes.

     Delilah Road Landfill Site. In November 1991, the New Jersey Department of Environmental Protection (NJDEP) identified ACE as a potentially responsible party (PRP) at the Delilah Road Landfill site in Egg Harbor Township, New Jersey. In 1993, ACE, along with other PRPs, signed an administrative consent order with NJDEP to remediate the site. The soil cap remedy for the site has been completed and the NJDEP conditionally approved the report submitted by the parties on the implementation of the remedy in January 2003. In March 2004, NJDEP approved a Ground Water Sampling and Analysis Plan. Positive results of groundwater monitoring events have resulted in a reduced level of groundwater monitoring. In August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site. Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years a nd to continue quarterly groundwater monitoring. In September 2007, NJDEP approved the PRP group's December 2006 petition seeking approval of 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 request for annual groundwater monitoring thereafter. In August 2007, the PRP group agreed to reimburse EPA's costs in the amount of $81,400 in full satisfaction of EPA's claims for all past and future response costs relating to the site (of which ACE's share is one-third) and in October 2007, EPA and the PRP group entered into a tolling agreement to permit the parties sufficient time to execute a final settlement agreement. This settlement agreement will allow the United States Environmental Protection Agency 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

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operation and maintenance costs will not have a material adverse effect on its financial position, results of operations or cash flows.

     Frontier Chemical Site. On June 29, 2007, ACE received a letter from the New York Department of Environmental Conservation (NYDEC) indicating that ACE is a PRP at the Frontier Chemical Waste Processing Company site in Niagara Falls, N.Y. The letter states that NYDEC has hazardous waste manifests indicating that ACE sent in excess of 7,500 gallons of manifested hazardous waste to the site. ACE informed NYDEC that it has entered into good faith negotiations with a coalescing PRP group to address ACE's responsibility at the site and in October 2007, ACE entered into an agreement with the other PRPs to form the PRP group. 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.

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 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 $49 million, primarily attributable to its 2001 tax returns.

     On August 2, 2005, the Treasury Department released regulations that, if adopted in their current form, would require 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 those regulations, PHI in its 2005 Federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believes will be acceptable to the IRS.

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

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

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(5)  DISCONTINUED OPERATIONS

     As discussed in Note (4) "Commitments and Contingencies," herein, on February 8, 2007, ACE completed the sale of its 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 Statements of Earnings for the three and nine months ended September 30, 2007 and 2006. In September 2006, ACE sold its interests in the Keystone and Conemaugh generating facilities, which for the three and nine months ended September 30, 2006, also were reflected as "discontinued operations."

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

	For the Three Months Ended September 30,		For the Nine Months Ended September 30,
	2007	2006	2007	2006
	(Millions of dollars)
Operating Revenue	$   -	$45.5	$9.7	$100.5
Income Before Income Tax Expense	$   -	$  1.1	$ .2	$   3.8
Net Income	$   -	$   .7	$ .1	$   2.3

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

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

Registrants	Page No.
Pepco Holdings	105
Pepco	159
DPL	167
ACE	176

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

PEPCO HOLDINGS, INC.

GENERAL OVERVIEW

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

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

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

     The Power Delivery business is the largest component of PHI's business. For the three months ended September 30, 2007 and 2006, the operating revenues of the Power Delivery business (including intercompany amounts) were equal to 58% and 64% of PHI's consolidated operating revenues, and the operating income of the Power Delivery business (including income from intercompany transactions) was equal to 68%, and 71% of PHI's consolidated operating income, respectively. For the nine months ended September 30, 2007 and 2006, the operating revenues of the Power Delivery business (including intercompany amounts) were equal to 57% and 62% of PHI's consolidated operating revenues, and the operating income of the Power Delivery business (including income from intercompany transactions) was equal to 68%, and 70% of PHI's consolidated operating income, respectively.

     The Power Delivery business consists primarily of the transmission, distribution and default supply of electric power, which was responsible for 97% and 98% of Power Delivery's operating revenues for the three-month periods ended September 30, 2007 and 2006, and 95% for each of the nine-month periods ended September 30, 2007 and 2006. The distribution of natural gas contributed 3% and 2% of Power Delivery's operating revenues for the three-month periods ended September 30, 2007 and 2006, and 5% for each of the nine-month periods ended September 30, 2007 and 2006. Power Delivery represents one operating segment for financial reporting purposes.

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

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

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Maryland	SOS
New Jersey	Basic Generation Service (BGS)
Virginia	Default Service

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

     Pepco, DPL, and ACE are transmission-owning members of the PJM Regional Transmission Organization. PJM Interconnection, LLC (PJM), as the transmission provider, is responsible for the transmission of wholesale electricity into and across the PJM geographical area. The rates each company is permitted to charge for the wholesale transmission of electricity are regulated by the Federal Energy Regulatory Commission (FERC). Each company is entitled to earn a FERC approved return on equity of 10.8% for facilities existing prior to January 1, 2006 and 11.3% for facilities put into service thereafter.

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

     The Competitive Energy business provides competitive generation, marketing and supply of electricity and gas, and related energy management services primarily in the mid-Atlantic region. These operations are conducted through subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv Energy) and Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), each of which is treated as a separate operating segment for financial reporting purposes. For the three months ended September 30, 2007 and 2006, the operating revenues of the Competitive Energy business (including intercompany amounts) were equal to 46% and 41% of PHI's consolidated operating revenues, respectively, and the operating income of the Competitive Energy business (including operating income from intercompany transactions) was 26% and 19%, respectively, of PHI's consolidated operating income over the same periods. For the nine months ended September 30, 2007 and 2006, the operating revenues of the Competitive Energy business (including intercompany amounts) were equal to 47% and 43%, respectively, of PHI's consolidated operating revenues, and the operating income of the Competitive Energy business (including operating income from intercompany transactions) was 24% and 18%, respectively, of PHI's consolidated operating income over the same periods. For the three months ended September 30, 2007 and 2006 amounts equal to 10% and 14%, 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, 2007 and 2006, amounts equal to 10% and 13%, respectively, of the operating revenues of the Competitive Energy business were attributable to electric energy and capacity, and natural gas sold to the Power Delivery segment.

· Conectiv Energy provides wholesale electric power, capacity and ancillary services in the wholesale markets administered by PJM and also supplies electricity to other wholesale market participants under long and short-term bilateral contracts. Conectiv Energy also supplies electric power to satisfy a portion of ACE's New Jersey, Pepco's

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Maryland and DPL's Delaware, Maryland, and Virginia Default Electricity Supply load, as well as default electricity supply load shares of other utilities. PHI refers to these activities as Merchant Generation and Load Service. Conectiv Energy obtains the electricity required to meet its Merchant Generation and Load Service power supply obligations from its own generation plants, bilateral contract purchases from other wholesale market participants, and purchases in the PJM wholesale market. Conectiv Energy also sells natural gas and fuel oil to very large end-users and to wholesale market participants under bilateral agreements. PHI refers to these sales operations as Energy Marketing.

·

Pepco Energy Services provides retail energy supply and energy services primarily to commercial, industrial, and government customers. Pepco Energy Services sells electricity and natural gas to customers primarily in the mid-Atlantic region. Pepco Energy Services owns and operates two district energy systems, provides energy savings performance contracting services, and designs, constructs and operates combined heat and power and central energy plants. Pepco Energy Services provides high voltage construction and maintenance services to customers throughout the U.S. and low voltage construction and maintenance services in the Washington, D.C. area and owns and operates electric generating plants in Washington, D.C.

     Conectiv Energy's primary objective is to maximize the value of its generation fleet by leveraging its operational and fuel flexibilities. Pepco Energy Services' primary objective is to capture retail energy supply and service opportunities primarily in the mid-Atlantic region. The financial results of the Competitive Energy business can be significantly affected by wholesale and retail energy prices, the cost of fuel to operate the Conectiv Energy plants, and the cost of purchased energy necessary to meet its power supply obligations.

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

     Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy sale-leaseback transactions with a book value at September 30, 2007 of approximately $1.4 billion. This activity constitutes a fourth operating segment, which is designated as "Other Non-Regulated," for financial reporting purposes. For a discussion of PHI's cross-border leasing transactions, see "Regulatory and Other Matters -- Federal Tax Treatment of Cross-border Leases."

     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, 2006.

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EARNINGS OVERVIEW

Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2006

     PHI's net income for the three months ended September 30, 2007 was $167.6 million, or $.87 per share, compared to $104.0 million, or $.54 per share, for the comparable period in 2006.

     Net income for 2007 included the credits set forth below (which are presented net of tax and in millions of dollars). The segment that recognized the credit is also indicated.

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

     Net income for 2006 included the (charge) set forth below (which is presented net of tax and in millions of dollars). The segment that recognized the (charge) is also indicated.

·	Pepco Energy Services
	Impairment losses related to certain energy services         business assets	$(7.9)

     Excluding the items listed above for the three months ended September 30, net income would have been $129.9 million in 2007 and $111.9 million in 2006.

     PHI's net income for the three months ended September 30, 2007 compared to the corresponding period in 2006 is set forth in the table below (millions of dollars):

	2007	2006	Change
Power Delivery	$122.6	$  83.5	$39.1
Conectiv Energy	36.5	22.5	14.0
Pepco Energy Services	9.8	(.3)	10.1
Other Non-Regulated	11.2	9.8	1.4
Corporate & Other	(12.5)	(11.5)	(1.0)
Total PHI Net Income (GAAP)	$167.6	$104.0	$63.6

Discussion of Segment Net Income Variances:

     Power Delivery's $39.1 million increase in earnings is primarily due to the following:

· $20.0 million increase due to the recovery of operating expenses and certain other costs associated with the Mirant bankruptcy damage claims settlement.

· $17.7 million increase due to the settlement of a Maryland income tax refund claim relating to the divestiture of Pepco generation assets in 2000, net of $1.8 million (after-tax) in professional fees.

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· $13.7 million increase due to the impact of the Maryland rate orders effective June 16, 2007 for Pepco and Delmarva.

· $7.4 million increase due to a FERC network transmission formula rate change in June 2007.

· $9.0 million decrease due to income tax adjustments.

· $6.7 million decrease due to higher operation and maintenance (O&M) costs - primarily higher employee-related costs. The $6.7 million unfavorable O&M earnings variance excludes $1.8 million (after-tax) in professional fees associated with the Maryland Income Tax Refund settlement (reflected in the item above).

· $1.1 million decrease due to lower Default Electricity Supply margins primarily as a result of customers electing to purchase their electricity from competitive suppliers.

     Conectiv Energy's $14.0 million increase in earnings is primarily due to the following:

· $18.0 million increase in Merchant Generation and Load Service primarily due to higher output, higher capacity prices and improved hedge results.

· $6.5 million decrease due to lower Energy Marketing margins primarily in its oil marketing activities.

     Pepco Energy Services' $10.1 million increase in earnings is primarily due to the following:

· $7.9 million increase due to the impairment losses on certain energy services business assets in 2006.

· $4.9 million increase from its retail energy supply businesses of which a $7.8 million increase is from its retail electric business related to more favorable congestion costs and higher electric volumes in 2007, partially offset by a $2.9 million decrease from its retail natural gas business due to lower volumes and higher cost of supply in 2007.

· $2.9 million decrease from its energy services business primarily due to planned major overhaul services in 2007.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

     PHI's net income for the nine months ended September 30, 2007 was $276.4 million, or $1.43 per share, compared to $212.0 million, or $1.11 per share, for the comparable period in 2006.

     Net income for 2007 included the credits set forth below (which are presented net of tax and in millions of dollars). The segment that recognized the credit is also indicated.

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

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    Net income for 2006 included the (charges) and credits set forth below (which are presented net of tax and in millions of dollars). The segment that recognized the (charge) or credit is also indicated.

·	Conectiv Energy
	Gain on disposition of assets associated with a         co-generation facility	$7.9
·	Pepco Energy Services
	Impairment losses related to certain energy services         business assets	$(12.1)

     Excluding the items listed above for the nine months ended September 30, net income would have been $238.7 million in 2007 and $216.2 million in 2006.

     PHI's net income for the nine months ended September 30, 2007 compared to the corresponding period in 2006 is set forth in the table below (millions of dollars):

	2007	2006	Change
Power Delivery	$202.2	$169.1	$33.1
Conectiv Energy	57.3	41.2	16.1
Pepco Energy Services	23.1	13.4	9.7
Other Non-Regulated	37.4	38.0	(0.6)
Corporate & Other	(43.6)	(49.7)	6.1
Total PHI Net Income (GAAP)	$276.4	$212.0	$64.4

Discussion of Segment Net Income Variances:

     Power Delivery's $33.1 million increase in earnings is primarily due to the following:

· $20.0 million increase due to the recovery of operating expenses and certain other costs associated with the Mirant bankruptcy damage claims settlement.

· $17.7 million increase due to the settlement of a Maryland income tax refund claim relating to the divestiture of Pepco generation assets in 2000, net of $1.8 million (after-tax) in professional fees.

· $13.7 million increase due to the impact of the Maryland rate orders effective June 16, 2007 for Pepco and Delmarva.

· $22.0 million increase primarily due to higher distribution sales (favorable impact of weather compared to 2006).

· $15.2 million decrease due to higher O&M costs - primarily electric system maintenance, various construction project write-offs related to customer requested work, employee related costs, regulatory costs and increased bad debt expense. The $15.2 million unfavorable O&M earnings variance excludes $1.8 million (after-tax) in professional fees associated with the Maryland Income Tax Refund settlement (reflected in the item above).

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· $8.1 million decrease due to income tax adjustments.

· $4.5 million decrease due to a FERC network transmission formula rate change in June 2006; partially offset by the rate change in June 2007.

· $5.6 million decrease due to lower Default Electricity Supply margins primarily as a result of customers electing to purchase electricity from competitive suppliers.

     Conectiv Energy's $16.1 million increase in earnings is primarily due to the following:

· $30.7 million increase in Merchant Generation and Load Service primarily due to higher generation output and higher capacity prices.

· $3.3 million decrease due to lower Energy Marketing margins.

· $7.9 million decrease due to the gain in disposition of assets associated with a co-generation facility in 2006.

· $5.0 million decrease due to higher plant maintenance costs.

     Pepco Energy Services' $9.7 million increase in earnings is primarily due to the following:

· $12.1 million increase due to the impairment losses on certain energy services business assets in 2006.

· $2.7 million decrease from its retail energy supply businesses of which a $0.6 million decrease is from its retail electric business due to gains on sale of excess supply and reduction in operating expenses in 2006, partially offset by earnings from higher volumes and more favorable congestion costs in 2007, and a $2.1 million decrease from its retail natural gas business due to lower volumes and higher cost of supply in 2007.

     Corporate and Other's $6.1 million increase in earnings is primarily due to the following:

· $7.3 million increase due to prior year tax audit adjustment (tax benefits were recorded by other segments and eliminated in consolidation through Corporate and Other).

· $1.9 million decrease due to higher interest expense.

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CONSOLIDATED RESULTS OF OPERATIONS

     The accompanying results of operations discussion is for the three months ended September 30, 2007, compared to the three months ended September 30, 2006. All amounts in the tables (except sales and customers) are in millions.

Operating Revenue

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

	2007		2006		Change
Power Delivery	$	1,596.3	$	1,660.7	$	(64.4)
Conectiv Energy		633.2		566.8		66.4
Pepco Energy Services		654.4		488.3		166.1
Other Non-Regulated		19.6		21.4		(1.8)
Corp. & Other		(133.2)		(147.3)		14.1
Total Operating Revenue	$	2,770.3	$	2,589.9	$	180.4

     Power Delivery Business

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

	2007		2006		Change
Regulated T&D Electric Revenue	$	499.6	$	454.1	$	45.5
Default Supply Revenue		1,037.6		1,157.3		(119.7)
Other Electric Revenue		15.8		15.3		.5
Total Electric Operating Revenue		1,553.0		1,626.7		(73.7)
Regulated Gas Revenue		19.2		19.8		(.6)
Other Gas Revenue		24.1		14.2		9.9
Total Gas Operating Revenue		43.3		34.0		9.3
Total Power Delivery Operating Revenue	$	1,596.3	$	1,660.7	$	(64.4)

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

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

     Other Electric Revenue consists of utility-related work and services performed on behalf of customers, including other utilities, which is not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rents, late payments, and collection fees.

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

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

Electric Operating Revenue

Regulated T&D Electric Revenue	2007		2006		Change
Residential	$	198.9	$	196.8	$	2.1
Commercial		210.7		199.1		11.6
Industrial		7.2		7.2		-
Other (Includes PJM)		82.8		51.0		31.8
Total Regulated T&D Electric Revenue	$	499.6	$	454.1	$	45.5

Regulated T&D Electric Sales (gigawatt hours (GWh))	2007		2006		Change
Residential		5,458		5,571		(113)
Commercial		8,096		8,035		61
Industrial		977		1,068		(91)
Other		59		58		1
Total Regulated T&D Electric Sales		14,590		14,732		(142)

Regulated T&D Electric Customers (000s)	2007		2006		Change
Residential		1,616		1,602		14
Commercial		197		196		1
Industrial		2		2		-
Other		2		2		-
Total Regulated T&D Electric Customers		1,817		1,802		15

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

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

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

     Regulated T&D Electric Revenue increased by $45.5 million primarily due to the following: (i) $15.4 million increase from resale of energy and capacity under an agreement with Panda-Brandywine LLP, an independent power producer (Panda) to purchase 230 megawatts of

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capacity and energy annually through 2021 (Panda PPA), in the PJM market (offset in Fuel and Purchased Energy and Other Services Cost of Sales Expense), (ii) $12.5 million increase in network transmission revenues, primarily due to an increase in the FERC formula rate in June 2007, (iii) $6.8 million increase primarily due to increased Pepco and DPL distribution rates in Maryland beginning in June 2007, (iv) $4.1 million increase due to a DPL adjustment to reclassify market-priced supply revenue to Default Supply Revenue in 2006, (v) $3.9 million increase due to the effect of the Maryland bill stabilization adjustment (BSA) implemented in June 2007, (vi) $3.2 million increase due to higher pass-through revenue resulting from rate increases (offset in Other Taxes), (vii) $1.9 million increase due to customer growth of 1% in 2007, (viii) $1.6 million increase in weather-related sales (a 56% decrease in Heating Degree Days and a 3% increase in Cooling Degree Days), partially offset by (ix) $3.9 million decrease due to differences in consumption among the various customer rate classes.

     Default Electricity Supply

Default Supply Revenue	2007		2006		Change
Residential	$	607.9	$	586.8	$	21.1
Commercial		325.5		436.7		(111.2)
Industrial		24.6		25.8		(1.2)
Other (Includes PJM)		79.6		108.0		(28.4)
Total Default Supply Revenue	$	1,037.6	$	1,157.3	$	(119.7)

Default Electricity Supply Sales (GWh)	2007		2006		Change
Residential		5,314		5,427		(113)
Commercial		2,810		3,668		(858)
Industrial		237		196		41
Other		24		23		1
Total Default Electricity Supply Sales		8,385		9,314		(929)

Default Electricity Supply Customers (000s)	2007		2006		Change
Residential		1,585		1,571		14
Commercial		169		173		(4)
Industrial		1		1		-
Other		2		2		-
Total Default Electricity Supply Customers		1,757		1,747		10

     Default Supply Revenue decreased by $119.7 million primarily due to the following: (i) $61.1 million decrease primarily due to an increase in commercial and industrial customers electing to purchase electricity from competitive suppliers, (ii) $40.0 million decrease due to differences in consumption among the various customer rate classes, (iii) $26.9 million decrease in wholesale energy revenue primarily due to the sales by ACE of its Keystone and Conemaugh interests and the B.L. England generating facilities, (iv) $4.1 million decrease due to a DPL adjustment to reclassify market-priced supply revenue from Transmission and Delivery revenue

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in 2006, (v) $1.2 million decrease due to weather-related sales (a 56% decrease in Heating Degree Days and a 3% increase in Cooling Degree Days), partially offset by (vi) $13.6 million increase due to higher retail electricity rates, primarily the result of new market based rates (primarily offset in Fuel and Purchased Energy and Other Services Cost of Sales).

     Gas Operating Revenue

Regulated Gas Revenue	2007		2006		Change
Residential	$	9.5	$	8.9	$	.6
Commercial		6.8		7.6		(.8)
Industrial		1.5		2.1		(.6)
Transportation and Other		1.4		1.2		.2
Total Regulated Gas Revenue	$	19.2	$	19.8	$	(.6)

Regulated Gas Sales (billion cubic feet (Bcf))	2007		2006		Change
Residential		.5		.4		.1
Commercial		.3		.4		(.1)
Industrial		.1		.2		(.1)
Transportation and Other		1.4		1.4		-
Total Regulated Gas Sales		2.3		2.4		(.1)

Regulated Gas Customers (000s)	2007		2006		Change
Residential		112		111		1
Commercial		9		9		-
Industrial		-		-		-
Transportation and Other		-		-		-
Total Regulated Gas Customers		121		120		1

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

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

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

     Regulated Gas Revenuedecreasedby $0.6 million primarily due to (i) $1.3 million decrease due to Gas Cost Rate (GCR) decreases effective in November 2006 and April 2007 due to lower natural gas commodity costs (offset in Fuel and Purchased Energy and Other Services Cost of Sales), partially offset by (ii) $1.2 million increase due to base rate increases effective November 2006 and April 2007.

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     Other Gas Revenue increased by $9.9 million to $24.1 million in 2007 from $14.2 million in 2006 primarily due to higher off-system sales (partially offset in Fuel and Purchased Energy and Other Services Cost of Sales).

     Competitive Energy Businesses

     Conectiv Energy

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

     Operating Revenues of the Conectiv Energy segment are derived primarily from the sale of electricity. The primary components of its Costs of Sales are fuel and purchased power. Because fuel and electricity prices tend to move in tandem, price changes in these commodities from period to period can have a significant impact on Operating Revenue and Costs of Sales without signifying any change in the performance of the Conectiv Energy segment. For this reason, PHI from a managerial standpoint focuses on gross margin as a measure of performance.

     Conectiv Energy Gross Margin

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

     Energy Marketing activities consist primarily of wholesale natural gas and fuel oil marketing; the activities of the real-time power desk, which generates margin by capturing price differences between power pools, and locational and timing differences within a power pool; and prior to October 31, 2006, provided operating services under an agreement with an unaffiliated generating plant. Beginning in 2007, power origination activities, which primarily represent the fixed margin component of structured power transactions such as default supply service, have been reclassified into Energy Marketing from Merchant Generation & Load Service. The 2006 activity has been reclassified for comparative purposes accordingly. Power origination makes up $5.4 million and $8.2 million of gross margin for the third quarter of 2007 and 2006 respectively.

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	Three Months Ended September 30,
	2007		2006
Operating Revenue ($ millions):
Merchant Generation & Load Service	$312.7		$310.4
Energy Marketing	320.5		256.4
Total Operating Revenue1	$633.2		$566.8
Cost of Sales ($ millions):
Merchant Generation & Load Service	$213.5		$241.4
Energy Marketing	314.9		239.8
Total Cost of Sales2	$528.4		$481.2
Gross Margin ($ millions):
Merchant Generation & Load Service	$  99.2	$  69.0
Energy Marketing	5.6	16.6
Total Gross Margin	$104.8	$  85.6
Generation Fuel and Purchased Power Expenses ($ millions) 3:
Generation Fuel Expenses 4,5
Natural Gas	$  118.8	$  98.5
Coal	16.0	14.2
Oil	9.9	20.2
Other6	0.6	1.6
Total Generation Fuel Expenses	$  145.3	$134.5
Purchased Power Expenses 5	$  155.9	$  68.9
Statistics:	2007	2006
Generation Output (MWh):
Base-Load 7	606,378	455,119
Mid-Merit (Combined Cycle) 8	1,525,545	1,081,737
Mid-Merit (Oil Fired) 9	77,718	120,799
Peaking	80,063	95,732
Tolled Generation	92,630	76,622
Total	2,382,334	1,830,009
Load Service Volume (MWh) 10	1,868,639	1,831,092
Average Power Sales Price 11 ($/MWh):
Generation Sales 4	$88.89	$96.11
Non-Generation Sales 12	$68.47	$73.39
Total	$75.84	$81.37
Average on-peak spot power price at PJM East Hub ($/MWh) 13	$88.08	$81.67
Average around-the-clock spot power price at PJM East Hub ($/MWh) 13	$68.14	$61.56
Average spot natural gas price at market area M3 ($/MMBtu)14	$  6.69	$  6.67
Weather (degree days at Philadelphia Airport): 15
Heating degree days	19	53
Cooling degree days	1,005	858
1 Includes $131.4 million and $144.8 million of affiliate transactions for 2007 and 2006, respectively. The 2006 figure has been reclassified to        exclude $66.8 million of affiliate transactions that eliminate within the segment.
2 Includes $1.3 million and $1.4 million of affiliate transactions for 2007 and 2006, respectively. The 2006 figure has been reclassified to        exclude $66.8 million of affiliate transactions that eliminate within the segment. Also, excludes depreciation and amortization expense        of $9.3 million and $9.0 million, respectively.
3 Consists solely of Merchant Generation & Load Service expenses; does not include the cost of fuel not consumed by the power plants        and intercompany tolling expenses.
4 Includes tolled generation.
5 Includes associated hedging gains and losses.
6 Includes emissions expenses, fuel additives, and other fuel-related costs.
7 Edge Moor Units 3 and 4 and Deepwater Unit 6.
8 Hay Road and Bethlehem, all units.
9 Edge Moor Unit 5 and Deepwater Unit 1. Generation output for these units was negative for the first quarter of 2006 because of station        service consumption.
10 Consists of all default electricity supply sales; does not include standard product hedge volumes.
11 Calculated from data reported in Conectiv Energy's Electric Quarterly Report (EQR) filed with the FERC; does not include        capacity or ancillary services revenue.
12 Consists of default electricity supply sales, standard product power sales, and spot power sales other than merchant generation as        reported in Conectiv Energy's EQR.
13 Source: PJM website (www.pjm.com).
14 Source: Average delivered natural gas price at Tetco Zone M3 as published in Gas Daily.
15 Source: National Oceanic and Atmospheric Administration National Weather Service data.

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     Merchant Generation & Load Service gross margin increased $30.2 million primarily due to:

· An increase of $39.1 million primarily due to increases in generation output due to more favorable weather and improved availability at the Hay Road and Deepwater generating plants and higher capacity prices due to the implementation of the PJM Reliability Pricing Model. The higher capacity prices, which had a positive impact on generation margin, had a partially offsetting effect on the cost of fulfilling Default Electricity Supply obligations.

· An increase of $31.6 million attributable to power and fuel hedges primarily due to higher margin power sales in 2007 and falling fuel prices in 2006.

· A decrease of $27.4 million related to Default Electricity Supply contracts caused by higher capacity costs in 2007 and a mark-to-market gain in 2006.

· A decrease of $13.2 million primarily due to a mark-to-market loss on excess natural gas supply.

     Energy Marketing gross margin decreased $11.0 million primarily due to:

· A decrease of $6.4 million due to lower margins in oil marketing.

· A decrease of $3.2 million due to lower margins in natural gas marketing.

     Pepco Energy Services

     Pepco Energy Services' operating revenue increased $166.1 million primarily due to (i) an increase of $170.7 million due to higher volumes of retail electric load served at higher prices in 2007 driven by customer acquisitions, (ii) an increase of $7.0 million due to higher volumes of wholesale natural gas sales in 2007 that resulted from increased natural gas supply utilization for operational flexibility, partially offset by (iii) a decrease of $11.7 million due to less construction activities in the 2007 quarter.

     Other Non-Regulated

     Other Non-Regulated operating revenue decreased $1.8 million to $19.6 million in 2007 from $21.4 million in 2006. The operating revenue of this segment primarily consists of lease earnings recognized under Statement of Financial Accounting Standards No. 13, "Accounting for Leases." The revenue decrease is primarily due to a change in lease assumptions that resulted in increased revenue in 2006 as compared to 2007.

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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:

	Three Months Ended September 30,
	2007		2006		Change
Power Delivery	$	1,040.3	$	1,106.4	$	(66.1)
Conectiv Energy		528.4		481.2		47.2
Pepco Energy Services		615.0		456.8		158.2
Corporate and Other		(132.5)		(146.6)		14.1
Total	$	2,051.2	$	1,897.8	$	153.4

     Power Delivery Business

     Power Delivery's Fuel and Purchased Energy which is primarily associated with Default Electric Supply sales, decreased by $66.1 million primarily due to: (i) $111.9 million decrease due to an increase in commercial and industrial customers electing to purchase electricity from competitive suppliers, (ii) $5.8 million decrease in the Default Electricity Supply deferral balance, partially offset by (iii) $36.2 million increase in average energy costs, the result of new annual Default Electricity Supply contracts, and (iv) $15.4 million increase due to the change in accounting for energy and capacity purchases under the Panda PPA due to termination of the "back-to-back" arrangement with Mirant (offset in Regulated T&D Electric 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 $158.2 million primarily due to (i) an increase of $154.3 million due to higher volumes of purchased electricity at higher prices in 2007 to serve increased retail customer load and (ii) an increase of $10.6 million due to higher volumes of wholesale natural gas purchases in 2007 that resulted from increased natural gas supply utilization for operational flexibility, partially offset by (iii) a decrease of $6.8 million due to less construction activities in 2007.

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     Other Operation and Maintenance

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

	Three Months Ended September 30,
	2007		2006		Change
Power Delivery	$	170.7	$	162.2	$	8.5
Conectiv Energy		26.8		29.0		(2.2)
Pepco Energy Services		19.3		15.9		3.4
Other Non-Regulated		.5		1.8		(1.3)
Corporate and Other		(3.0)		(8.8)		5.8
Total	$	214.3	$	200.1	$	14.2

     Other Operation and Maintenance expenses of the Power Delivery segment increased by $8.5 million; however, excluding the favorable variance of $8.5 million in Other Operations and Maintenance expenses primarily resulting from ACE's exit from operations at the B.L. England electric generating facility that was sold in February 2007, Other Operations and Maintenance expenses for the ongoing operations of the Power Delivery segment increased by $17.0 million. The $17.0 million increase was primarily due to (i) $8.9 million increase in employee related costs, (ii) $2.9 million increase in professional fees related to the Maryland income tax refund claim, (iii) $2.8 million increase in business support costs primarily customer services and accounting, (iv) $1.6 million increase due to uncollectible reserve adjustments, partially offset by (v) $2.4 million decrease primarily due to reclassification of rate case costs to be recovered in future periods in accordance with the June 20 07 Maryland rate order.

     Other Operation and Maintenance expenses related to Corporate and Other increased primarily due to reduced employee-related costs in 2006.

     Depreciation and Amortization

     PHI's depreciation and amortization expenses decreased by $22.8 million to $87.6 million in 2007 from $110.4 million in 2006. The decrease is primarily due to (i) $9.0 million decrease due to a change in depreciation rates in accordance with the June 2007 Maryland rate order, and (ii) $13.7 million decrease in ACE's regulatory asset amortization primarily resulting from the 2006 sale of ACE's interests in Keystone and Conemaugh.

     Other Taxes

     Other Taxes increased by $4.1 million to $100.0 million in 2007, from $95.9 million in 2006. The increase was primarily due to $3.5 million increased pass-throughs resulting from rate increases (partially offset in Regulated T&D Electric Revenue).

     Deferred Electric Service Costs

     Deferred Electric Service Costs, which relates only to ACE, decreased by $1.6 million to an expense of $29.1 million in 2007 from an expense of $30.7 million in 2006. The decrease represents net under-recovery associated with New Jersey BGS, NUGS, market transition charges and other restructuring items. At September 30, 2007, ACE's balance sheet included

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as a regulatory liability an over-recovery of $227.1 million with respect to these items, which is net of a $46.0 million reserve for items disallowed by the New Jersey Board of Public Utilities (NJBPU) in a ruling that is under appeal. The $227.1 million regulatory liability also includes an $81.3 million gain related to the 2006 sale of ACE's interests in Keystone and Conemaugh, a $24.9 million gain on sale of emission credits related to the B.L. England generating facility, and a $14.7 million loss related to ACE's 2007 sale of B.L. England.

     Impairment Loss

     During the three months ended September 30, 2006, Pepco Holdings recorded pre-tax impairment losses of $12.6 million ($7.9 million, after-tax) on certain energy services business assets owned by Pepco Energy Services. No impairment losses were recorded for the three months ended September 30, 2007.

     Effect of Settlement of Mirant Bankruptcy Claims

     The Effect of Settlement of Mirant Bankruptcy Claims reflects the recovery 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) decreased by $3.3 million to $72.9 million in 2007 from $76.2 million in 2006, primarily due to earnings recognized in 2007 from increases in the value of investment assets.

Income Tax Expense

     PHI's effective tax rate for the three months ended September 30, 2007 was 32% as compared to the Federal statutory rate of 35%. The major reasons for the difference between the effective tax rate and the statutory tax rate were the Maryland state tax refund (net of Federal benefit), tax benefits related to certain leveraged leases, and the flow-through of deferred investment tax credits, partially offset by state income taxes (net of Federal benefit), a deferred tax adjustment, the flow-through of certain book versus tax depreciation differences and changes in estimates related to tax liabilities of prior tax years subject to audit.

     PHI's effective tax rate for the three months ended September 30, 2006 was 37% as compared to the Federal statutory rate of 35%. The major reason for the difference between the effective tax rate and the statutory tax rate were state income taxes (net of Federal benefit) and the flow-through of certain book versus tax depreciation differences, partially offset by changes in estimates related to tax liabilities for prior tax years subject to audit, the flow-through of deferred investment tax credits and tax benefits related to certain leveraged leases.

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     The accompanying results of operations discussion is for the nine months ended September 30, 2007, compared to the nine months ended September 30, 2006. All amounts in the tables (except sales and customers) are in millions.

Operating Revenue

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

	2007		2006		Change
Power Delivery	$	4,033.7	$	4,014.9	$	18.8
Conectiv Energy		1,607.5		1,551.3		56.2
Pepco Energy Services		1,686.9		1,205.5		481.4
Other Non-Regulated		58.0		70.6		(12.6)
Corp. & Other		(352.7)		(383.9)		31.2
Total Operating Revenue	$	7,033.4	$	6,458.4	$	575.0

     Power Delivery Business

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

	2007		2006		Change
Regulated T&D Electric Revenue	$	1,236.4	$	1,194.9	$	41.5
Default Supply Revenue		2,527.7		2,583.0		(55.3)
Other Electric Revenue		48.4		43.1		5.3
Total Electric Operating Revenue		3,812.5		3,821.0		(8.5)
Regulated Gas Revenue		161.4		155.4		6.0
Other Gas Revenue		59.8		38.5		21.3
Total Gas Operating Revenue		221.2		193.9		27.3
Total Power Delivery Operating Revenue	$	4,033.7	$	4,014.9	$	18.8

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

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

     Other Electric Revenue consists of utility-related work and services performed on behalf of customers, including other utilities, which is not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rents, late payments, and collection fees.

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

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

Electric Operating Revenue

Regulated T&D Electric Revenue	2007		2006		Change
Residential	$	471.1	$	457.4	$	13.7
Commercial		553.9		535.2		18.7
Industrial		20.3		23.5		(3.2)
Other (Includes PJM)		191.1		178.8		12.3
Total Regulated T&D Electric Revenue	$	1,236.4	$	1,194.9	$	41.5

Regulated T&D Electric Sales (GWh)	2007		2006		Change
Residential		13,983		13,493		490
Commercial		22,129		21,624		505
Industrial		2,994		3,113		(119)
Other		185		185		-
Total Regulated T&D Electric Sales		39,291		38,415		876

Regulated T&D Electric Customers (000s)	2007		2006		Change
Residential		1,616		1,602		14
Commercial		197		196		1
Industrial		2		2		-
Other		2		2		-
Total Regulated T&D Electric Customers		1,817		1,802		15

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

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

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

     Regulated T&D Electric Revenue increased by $41.5 million primarily due to the following: (i) $29.1 million increase in sales due to higher weather-related sales (a 17% increase in Heating Degree Days and a 9% increase in Cooling Degree Days), (ii) $15.4 million increase in Other Regulated T&D Electric Revenue due to a change in the accounting for the resale of energy and capacity purchased under the Panda PPA, which by reason of the existence of the "back-to-back" arrangement with Mirant, which terminated in August 2007, was not previously recorded as revenue (offset in Fuel and Purchased Energy and Other Costs of Sales Expense), (iii) $6.8 million increase primarily due to increased Pepco and DPL distribution rates in Maryland beginning in June 2007, (iv) $6.7 million increase due to higher pass-through revenue

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resulting from rate increases (offset in Other Taxes), (v) $4.7 million increase due to customer growth of 1.0% in 2007, (vi) $3.9 million increase due to the effect of the Maryland BSA mechanism implemented in August 2007, (vii) $4.1 million increase due to a DPL adjustment to reclassify market-priced supply revenue to Default Supply Revenue in 2006, partially offset by (viii) $10.0 million decrease due to a change in Delaware rate structure effective May 1, 2006, which shifted revenue from Regulated T&D Electric Revenue to Default Supply Revenue, (ix) $8.2 million decrease due to differences in consumption among the various customer rate classes, (x) $7.0 million decrease in network transmission revenues, primarily due to a decrease in the FERC formula rate in June 2006, and (xi) $4.0 million decrease due to a Delaware base rate reduction effective May 1, 2006.

     Default Electricity Supply

Default Supply Revenue	2007		2006		Change
Residential	$	1,422.0	$	1,140.9	$	281.1
Commercial		820.4		1,082.5		(262.1)
Industrial		68.5		87.6		(19.1)
Other (Includes PJM)		216.8		272.0		(55.2)
Total Default Supply Revenue	$	2,527.7	$	2,583.0	$	(55.3)

Default Electricity Supply Sales (GWh)	2007		2006		Change
Residential		13,616		13,145		471
Commercial		7,629		12,114		(4,485)
Industrial		695		1,150		(455)
Other		102		100		2
Total Default Electricity Supply Sales		22,042		26,509		(4,467)

Default Electricity Supply Customers (000s)	2007		2006		Change
Residential		1,585		1,571		14
Commercial		169		173		(4)
Industrial		1		1		-
Other		2		2		-
Total Default Electricity Supply Customers		1,757		1,747		10

     Default Supply Revenue decreased by $55.3 million primarily due to the following: (i) $302.5 million decrease primarily due to an increase in commercial and industrial customers electing to purchase electricity from competitive suppliers, (ii) $90.4 million decrease due to differences in consumption among the various customer rate classes, (iii) $58.4 million decrease in wholesale energy revenue primarily from the sales by ACE of its Keystone and Conemaugh interests and the B.L. England generating facilities, (iv) $4.1 million decrease due to a DPL adjustment to reclassify market-priced supply revenue from Regulated T&D Electric Revenue in 2006, partially offset by (v) $339.3 million increase due to higher retail energy rates, primarily the result of new annual market-based rates, (vi) $50.8 million increase due to higher weather-related sales (an 17% increase in Heating Degree Days and a 9% increase in Cooling Degree Days), and (vii) $10.0 million increase d ue to a change in Delaware rate structure effective

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May 1, 2006 that shifted revenue from Regulated T&D Electric Revenue to Default Supply Revenue (partially offset in Fuel and Purchased Energy and Other Services Cost of Sales Expense).

Gas Operating Revenue

Regulated Gas Revenue	2007		2006		Change
Residential	$	94.6	$	88.3	$	6.3
Commercial		55.7		55.4		.3
Industrial		6.7		7.9		(1.2)
Transportation and Other		4.4		3.8		.6
Total Regulated Gas Revenue	$	161.4	$	155.4	$	6.0

Regulated Gas Sales (Bcf)	2007		2006		Change
Residential		5.6		4.6		1.0
Commercial		3.6		3.1		.5
Industrial		.6		.5		.1
Transportation and Other		4.9		4.5		.4
Total Regulated Gas Sales		14.7		12.7		2.0

Regulated Gas Customers (000s)	2007		2006		Change
Residential		112		111		1
Commercial		9		9		-
Industrial		-		-		-
Transportation and Other		-		-		-
Total Regulated Gas Customers		121		120		1

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

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

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

     Regulated Gas Revenue increased by $6.0 million primarily due to (i) $8.8 million increase due to colder weather (a 16% increase in Heating Degree Days), (ii) $6.1 million increase due to differences in consumption among the various customer rate classes, (iii) $4.0 million increase due to base rate increases effective in November 2006 and April 2007, (iv) $2.2 million increase due to customer growth of 1% in 2007, partially offset by (v) $15.1 million decrease due to GCR decreases effective November 2006 and April 2007 due to lower natural gas commodity costs (offset in Fuel and Purchased Energy and Other Services Cost of Sales).

     Other Gas Revenue increased by $21.3 million to $59.8 million in 2007 from $38.5 million in 2006 primarily due to higher off-system sales (partially offset in Fuel and Purchased Energy and Other Services Cost of Sales).

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     Competitive Energy Businesses

     Conectiv Energy

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

     Operating Revenues of the Conectiv Energy segment are derived primarily from the sale of electricity. The primary components of its Costs of Sales are fuel and purchased power. Because fuel and electricity prices tend to move in tandem, price changes in these commodities from period to period can have a significant impact on Operating Revenue and Costs of Sales without signifying any change in the performance of the Conectiv Energy segment. For this reason, PHI from a managerial standpoint focuses on gross margin as a measure of performance.

     Conectiv Energy Gross Margin

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

     Energy Marketing activities consist primarily of wholesale natural gas and fuel oil marketing; the activities of the real-time power desk, which generates margin by capturing price differences between power pools, and locational and timing differences within a power pool; and prior to October 31, 2006, provided operating services under an agreement with an unaffiliated generating plant. Beginning in 2007, power origination activities, which primarily represent the fixed margin component of structured power transactions such as default supply service, have been reclassified into Energy Marketing from Merchant Generation & Load Service. The 2006 activity has been reclassified for comparative purposes accordingly. Power origination contributed $16.2 million and $15.6 million of gross margin for the first nine months of 2007 and 2006 respectively.

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	Nine Months Ended September 30,
	2007		2006
Operating Revenue ($ millions):
Merchant Generation & Load Service	$788.4		$854.6
Energy Marketing	819.1		696.7
Total Operating Revenue1	$1,607.5		$1,551.3
Cost of Sales ($ millions):
Merchant Generation & Load Service	$574.0		$691.7
Energy Marketing	790.7		662.9
Total Cost of Sales2	$1,364.7		$1,354.6
Gross Margin ($ millions):
Merchant Generation & Load Service	$  214.4	$  162.9
Energy Marketing	28.4	33.8
Total Gross Margin	$  242.8	$  196.7
Generation Fuel and Purchased Power Expenses ($ millions) 3:
Generation Fuel Expenses 4,5
Natural Gas	$  201.4	$   151.0
Coal	46.6	39.9
Oil	24.6	26.7
Other6	1.8	3.1
Total Generation Fuel Expenses	$  274.4	$  220.7
Purchased Power Expenses 5	$  353.1	$  362.0
Statistics:	2007	2006
Generation Output (MWh):
Base-Load 7	1,654,766	1,375,466
Mid-Merit (Combined Cycle) 8	2,534,378	1,762,937
Mid-Merit (Oil Fired) 9	174,277	117,233
Peaking	96,917	128,003
Tolled Generation	112,230	86,922
Total	4,572,568	3,470,561
Load Service Volume (MWh) 10	5,488,076	7,156,463
Average Power Sales Price 11 ($/MWh):
Generation Sales 4	$83.22	$82.09
Non-Generation Sales 12	$69.81	$57.37
Total	$74.07	$62.37
Average on-peak spot power price at PJM East Hub ($/MWh) 13	$77.00	$68.64
Average around-the-clock spot power price at PJM East Hub ($/MWh) 13	$62.97	$55.97
Average spot natural gas price at market area M3 ($/MMBtu)14	$  7.78	$  7.38
Weather (degree days at Philadelphia Airport): 15
Heating degree days	3,031	2,712
Cooling degree days	1,403	1,124
1 Includes $334.9 million and $378.3 million of affiliate transactions for 2007 and 2006, respectively. The 2006 figure has been reclassified to        exclude $147.8 million of affiliate transactions that eliminate within the segment.
2 Includes $5.4 million and $3.4 million of affiliate transactions for 2007 and 2006, respectively. The 2006 figure has been reclassified to        exclude $147.8 million of affiliate transactions that eliminate within the segment. Also, excludes depreciation and amortization expense         of $27.9 million and $27.2 million, respectively.
3 Consists solely of Merchant Generation & Load Service expenses; does not include the cost of fuel not consumed by the power plants        and intercompany tolling expenses.
4 Includes tolled generation.
5 Includes associated hedging gains and losses.
6 Includes emissions expenses, fuel additives, and other fuel-related costs.
7 Edge Moor Units 3 and 4 and Deepwater Unit 6.
8 Hay Road and Bethlehem, all units.
9 Edge Moor Unit 5 and Deepwater Unit 1. Generation output for these units was negative for the first quarter of 2006 because of        station service consumption.
10 Consists of all default electricity supply sales; does not include standard product hedge volumes.
11 Calculated from data reported in Conectiv Energy's Electric Quarterly Report (EQR) filed with the FERC; does not include        capacity or ancillary services revenue.
12 Consists of default electricity supply sales, standard product power sales, and spot power sales other than merchant generation as        reported in Conectiv Energy's EQR.
13 Source: PJM website (www.pjm.com).
14 Source: Average delivered natural gas price at Tetco Zone M3 as published in Gas Daily.
15 Source: National Oceanic and Atmospheric Administration National Weather Service data.

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     Merchant Generation & Load Service gross margin increased $51.5 million primarily due to:

· An increase of $71.5 million primarily due to increases in generation output due to more favorable weather and improved availability at the Hay Road and Deepwater generating plants and higher capacity prices due to the implementation of the PJM Reliability Pricing Model.

· A decrease of $20.2 million primarily due to the expiration in 2006 of an agreement with an international investment banking firm to hedge approximately 50% of the commodity price risk of Conectiv Energy's generation and default electricity supply commitment to DPL, and less favorable power and natural gas fuel hedges.

     Energy Marketing gross margin decreased $5.4 million primarily due to:

· A decrease of $6.6 million due to lower margins in oil marketing.

· A decrease of $2.7 million due to lower margins in natural gas marketing.

· An increase of $3.3 million for adjustments resulting from a generation operating services agreement with an unaffiliated entity that expired in 2006.

Pepco Energy Services

     Pepco Energy Services' operating revenue increased $481.4 million primarily due to (i) an increase of $507.1 million due to higher volumes of retail electric load served at higher prices in 2007 driven by customer acquisitions, (ii) an increase of $7.9 million due to higher volumes of wholesale natural gas sales in 2007 that resulted from increased natural gas supply utilization for operational flexibility, partially offset by (iii) a decrease of $33.6 million due to less construction activities in 2007.

Other Non-Regulated

     Other Non-Regulated operating revenue decreased $12.6 million to $58.0 million in 2007 from $70.6 million in 2006. The operating revenue of this segment primarily consists of lease earnings recognized under Statement of Financial Accounting Standards No. 13, "Accounting for Leases." The revenue decrease is primarily due to changes in lease assumptions that resulted in increased revenue in 2006 as compared to 2007.

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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:

	Nine Months Ended September 30,
	2007		2006		Change
Power Delivery	$	2,612.3	$	2,592.7	$	19.6
Conectiv Energy		1,364.7		1,354.6		10.1
Pepco Energy Services		1,586.2		1,104.4		481.8
Corporate and Other		(349.9)		(383.2)		33.3
Total	$	5,213.3	$	4,668.5	$	544.8

     Power Delivery Business

     Power Delivery's Fuel and Purchased Energy which is primarily associated with Default Electric Supply sales, increased by $19.6 million primarily due to: (i) $405.8 million increase in average energy costs, the result of new Default Electricity Supply contracts, (ii) $55.3 million increase due to weather-related sales, (iii) $15.4 million increase due to the change in accounting for energy and capacity purchased under the Panda PPA due to the termination of the "back-to-back" arrangement with Mirant (offset in T&D Electric Revenue), partially offset by (iv) $420.4 million decrease primarily due to an increase in commercial and industrial customers electing to purchase electricity from competitive suppliers, (v) $24.5 million decrease in the Default Electricity Supply deferral balance, and (vi) $11.5 million decrease in network transmission expenses primarily due to Delaware POLR obligation ending April 2006 (partially offset in Default Supply Revenue, Regulate d 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 $481.8 million primarily due to (i) an increase of $502.9 million due to higher volumes of purchased electricity at higher prices in 2007 to serve increased retail customer load, (ii) an increase of $11.4 million due to higher volumes of wholesale natural gas sales in 2007 that resulted from increased natural gas supply utilization for operational flexibility, partially offset by (iii) a decrease of $32.5 million due to less construction activities in 2007.

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     Other Operation and Maintenance

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

	Nine Months Ended September 30,
	2007		2006		Change
Power Delivery	$	488.8	$	484.9	$	3.9
Conectiv Energy		94.9		86.6		8.3
Pepco Energy Services		54.8		49.3		5.5
Other Non-Regulated		3.0		4.9		(1.9)
Corporate and Other		(9.3)		(11.7)		2.4
Total	$	632.2	$	614.0	$	18.2

    Other Operations and Maintenance expenses of the Power Delivery segment increased by $3.9 million; however, excluding the favorable variance of $26.1 million in Other Operations and Maintenance expenses primarily resulting from ACE's exit from operations at the B.L. England electric generating facility that was sold in February 2007, Other Operations and Maintenance expenses for the ongoing operations of the Power Delivery segment increased by $30.0 million. The $30.0 million increase was primarily due to (i) $12.2 million increase in employee related costs, (ii) $7.4 million increase in business support costs primarily customer services and accounting, (iii) $6.0 million increase in operations, preventative maintenance and restoration, (iv) $3.3 million increase in regulatory expenses, (v) $3.1 million increase due to various construction project write-offs related to customer requested work, (vi) $2.2 million increase due to uncollectible reserve adjustments, (vii) $1.3 mil lion increase in Demand Side Management (offset in Deferred Electric Service costs), partially offset by (viii) $2.7 million decrease in company-owned life insurance expenses due to a 2006 adjustment, and (ix) $2.4 million decrease primarily due to the reclassification of rate case costs to be recovered in future periods in accordance with the June 2007 Maryland rate order.

     Other Operation and Maintenance expenses for Conectiv Energy increased by $8.3 million primarily due to higher plant maintenance costs due to more scheduled outages in 2007.

     Depreciation and Amortization

     Depreciation and Amortization expensesdecreased by $45.3 million to $273.4 million in 2007, from $318.7 million in 2006. The decrease is primarily due to (i) $38.7 million decrease in ACE's regulatory asset amortization resulting from the 2006 sale of ACE's interests in Keystone and Conemaugh, and (ii) $9.9 million decrease in depreciation due to a change in depreciation rates in accordance with the June 2007 Maryland rate order.

     Other Taxes

     Other Taxes increased by $11.6 million to $271.5 million in 2007, from $259.9 million in 2006. The increase was primarily due to increased pass-throughs resulting from rate increases (partially offset in Regulated T&D Electric Revenue).

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     Deferred Electric Service Costs

     Deferred Electric Service Costs, which relate only to ACE, increased by $26.7 million to an expense of $47.2 million in 2007 from an expense of $20.5 million in 2006. The increase represents a $26.7 million net over-recovery associated with New Jersey BGS, non-utility generation contracts between ACE and unaffiliated third parties, market transition charges and other restructuring items. At September 30, 2007, ACE's balance sheet included as a regulatory liability an over-recovery of $227.1 million with respect to these items, which is net of a $46.0 million reserve for items disallowed by the NJBPU in a ruling that is under appeal. The $227.1 million regulatory liability also includes an $81.3 million gain related to the 2006 sale of ACE's interests in Keystone and Conemaugh, a $24.9 million gain on sale of emission credits related to the B.L. England generating facility, and a $14.7 million loss related to ACE's 2007 sale of B.L. England.

     Impairment Loss

     During the nine months ended September 30, 2007 and 2006, Pepco Holdings recorded pre-tax impairment losses of $1.6 million and $19.1 million ($1.0 million and $12.1 million, after-tax) on certain energy services business assets owned by Pepco Energy Services.

     Effect of Settlement of Mirant Bankruptcy Claims

     The Effect of Settlement of Mirant Bankruptcy Claims reflects the recovery 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 $2.2 million to $212.4 million in 2007 from $210.2 million in 2006 due to a $12.3 million gain that was recorded in 2006 related to the disposition of assets associated with a cogeneration facility, partially offset in 2007 by a $2.5 million gain on a settlement agreement between Pepco Energy Services and a subcontractor and an increase in the value of investment assets.

Income Tax Expense

     PHI's effective tax rate for the nine months ended September 30, 2007 was 34% as compared to the Federal statutory rate of 35%. The major reasons for the difference between the effective tax rate and the statutory tax rate were the Maryland state tax refund (net of Federal benefit), tax benefits related to certain leveraged leases and the flow-through of deferred investment tax credits, partially offset by state income taxes (net of Federal benefit), a deferred tax adjustment and the flow-through of certain book versus tax depreciation differences.

     PHI's effective tax rate for the nine months ended September 30, 2006 was 39% as compared to the Federal statutory rate of 35%. The major reason for the difference between the effective tax rate and the statutory tax rate were state income taxes (net of Federal benefit) and the flow-through of certain book versus tax depreciation differences, partially offset by the flow-through of deferred investment tax credits and tax benefits related to certain leveraged leases.

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CAPITAL RESOURCES AND LIQUIDITY

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

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

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Financing Activity During the Three Months Ended September 30, 2007

     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.

Financing Activity Subsequent to September 30, 2007

     In October 2007, ACE Funding made principal payments of $6.5 million on Series 2002-1 Transition Bonds, Class A-1 and $2.6 million on Series 2003-1 Transition Bonds, Class A-1 with a weighted average interest rate of 2.89%.

     In October 2007, Pepco paid at maturity $175 million of 6.25% first mortgage bonds using the proceeds of commercial paper.

Sale of Interest in Cogeneration Joint Venture

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

Working Capital

     At September 30, 2007, Pepco Holdings' current assets on a consolidated basis totaled $2.1 billion and its current liabilities totaled $2.3 billion. At December 31, 2006, Pepco Holdings' current assets totaled $2.0 billion and its current liabilities totaled $2.5 billion.

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

     At September 30, 2007, Pepco Holdings' cash and cash equivalents and current restricted cash, totaled $41.1 million. No net cash collateral was held by subsidiaries of PHI engaged in Competitive Energy and Default Electricity Supply activities ($2.9 million of cash collateral was held as restricted cash).

     At December 31, 2006, Pepco Holdings' cash and cash equivalents and restricted cash totaled $60.8 million. No net cash collateral was held by subsidiaries of PHI engaged in Competitive Energy and Default Electricity Supply activities (no cash collateral was held as restricted cash). See "Capital Requirements -- Contractual Arrangements with Credit Rating Triggers or Margining Rights" for additional information.

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

	As of September 30, 2007 (Millions of dollars)
Type	PHI Parent	Pepco	DPL	ACE	ACE Funding	PES	PCI	PHI Consolidated
Variable Rate   Demand Bonds	$        -	$        -	$104.8	$22.6	$        -	$26.8	$      -	$154.2
Commercial Paper	81.2	151.0	135.2	74.6	-	-	-	442.0
Total Short-         Term Debt	$  81.2	$151.0	$240.0	$97.2	$        -	$26.8	$      -	$596.2
Current Maturities   of Long-Term Debt   and Project   Funding	$        -	$253.0	$  22.6	$50.0	$  30.7	$  2.7	$      -	$359.0

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

Cash Flow Activity

     PHI's cash flows for the nine months ended September 30, 2007 and 2006 are summarized below.

	Cash Use
		2007		2006
		(Millions of dollars)
Operating activities	$	462.5	$	(19.4)
Investing activities		(391.8)		(146.5)
Financing activities		(93.5)		87.6
Net decrease in cash and cash equivalents	$	(22.8)	$	(78.3)

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     Operating Activities

     Cash flows from operating activities during the nine months ended September 30, 2007 and 2006 are summarized below.

	Cash Source / (Use)
		2007		2006
		(Millions of dollars)
Net income	$	276.4	$	212.0
Non-cash adjustments to net income		318.6		333.1
Cash flows from settlement of Mirant bankruptcy claims		(17.8)		70.0
Changes in working capital		(114.7)		(634.5)
Net cash from (used by) operating activities	$	462.5	$	(19.4)

     Net cash from operating activities was $481.9 million higher for the nine months ended September 30, 2007 compared to the same period in 2006. The increase is primarily the result of: (i) a tax payment of $121 million made in February 2006 (see "Regulatory and Other Matters -- IRS Mixed Service Cost Issue" below) and (ii) the change in cash collateral requirements detailed below associated with the activities of Competitive Energy.

     Changes in cash collateral include the following:

· The balance of net cash collateral posted by PHI decreased $34.3 million from December 31, 2006 to September 30, 2007 (an increase in cash).

· The balance of net cash collateral posted by PHI increased $322.0 million from December 31, 2005 to September 30, 2006 (a decrease in cash).

     Cash flows from operating activities also include certain cash flows related to the Mirant bankruptcy settlement (see "Regulatory and Other Matters -- Final Resolution of Mirant Bankruptcy Matter). During the third quarter of 2007, Pepco Holdings received $413.9 million in net settlement proceeds, with $398.9 million designated as operating cash flows and $15.0 million designated as investing cash flows (see "Investing Activities" below). These funds were used to purchase money market funds, which are considered cash equivalents, and have been accounted for as restricted cash based on management's intent only to use such funds, and any interest earned thereon, to pay for the future above-market capacity and energy purchase costs under the Panda PPA. This restricted cash has been classified as a non-current asset to be consistent with the classification of the corresponding non-current regulatory liability, and any changes in the balance of this restricted cash, including interest receipts, have been considered operating cash flows. In August 2006, Pepco Holdings received a settlement payment of $70.0 million related to the Mirant bankruptcy matter which had become due in accordance with the terms of the Settlement Agreement with Mirant as a result of its approval by the Bankruptcy Court.

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     Investing Activities

     Cash flows from investing activities during the nine months ended September 30, 2007 and 2006 are summarized below.

	Cash Use
		2007		2006
		(Millions of dollars)
Construction expenditures	$	(422.7)	$	(356.3)
Cash proceeds from sale of:
Other investments		1.2		16.0
Other assets		10.6		180.6
Changes in restricted cash		4.9		5.9
All other investing cash flows, net		14.2		7.3
Net cash used by investing activities	$	(391.8)	$	(146.5)

     Net cash used by investing activities increased $245.3 million primarily due to: (i) a $66.4 million increase in capital expenditures, $41.8 million of which relates to Power Delivery, and (ii) a decrease in total cash proceeds from the sale of other investments and other assets of $184.8 million. The 2006 proceeds primarily consist of $177.0 million from the sale of ACE's interest in the Keystone and Conemaugh generating facilities and $13.1 million from the sale of Conectiv Energy's equity interest in a joint venture which owns a wood burning cogeneration facility in California. The 2007 proceeds consist of $9.0 million received from the sale of the B.L. England generating facility.

     Cash flows from investing activities also include $15.0 million of the net settlement proceeds related to the Mirant bankruptcy matter that were specifically designated as a reimbursement of certain investments in property, plant and equipment.

     Financing Activities

     Cash flows from financing activities during the nine months ended September 30, 2007 and 2006 are summarized below.

	Cash (Use) / Source
		2007		2006
		(Millions of dollars)
Dividends paid on common and preferred stock	$	(150.8)	$	(149.5)
Common stock issued for the Dividend Reinvestment Plan		21.0		22.6
Issuance of common stock		23.9		10.0
Preferred stock redeemed		(18.2)		(21.5)
Issuances of long-term debt		452.8		217.0
Reacquisition of long-term debt		(670.8)		(502.0)
Issuances of short-term debt, net		246.6		510.9
All other financing cash flows, net		2.0		.1
Net cash (used by) from financing activities	$	(93.5)	$	87.6

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     Net cash used by financing activities increased $181.1 million for the nine months ended September 30, 2007 compared to the same period in 2006.

     The decrease in net issuances of short-term debt was due to the following: (i) $300 million commercial paper issuance in 2006 used to retire PHI long-term debt, (ii) $174 million in short-term debt issued by DPL in 2006 primarily to cover construction expenditures of $104 million and tax payments of $45 million, offset by (iii) issuances of short-term debt in 2007 used to finance short-term liquidity needs and temporarily fund redemptions of long-term debt.

     Cash flows from the issuance and reacquisition of long-term debt in 2007 are 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%.

· 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.

· In June 2007, DPL retired at maturity $3.2 million of 6.95% first mortgage bonds.

· In July 2007, 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 its 5.5% notes using the proceeds of a June 2007 offering of $250 million of 6.125% ten-year notes and short-term debt.

     Cash flows from the issuance and reacquisition of long-term debt in 2006 were attributable primarily to the following transactions:

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

· In January 2006, ACE Funding made principal payments of $5.1 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 February 2006, PHI retired at maturity $300 million of its 3.75% unsecured notes with proceeds from the issuance of commercial paper.

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

· In April 2006, ACE Funding made principal payments of $4.8 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%.

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

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

· In July 2006, ACE Funding made principal payments of $4.6 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%.

     The change in the issuance of common of stock is related to increases in stock options exercised and shares issued under the performance based long-term incentive plan.

Capital Requirements

     Construction Expenditures

     Pepco Holdings' total construction expenditures for the nine months ended September 30, 2007 totaled $422.7 million of which $194.3 million related to Pepco (excluding $15 million of reimbursements related to the settlement of the Mirant bankruptcy claims), $92.4 million related to DPL and $91.0 million related to ACE. The remainder was primarily related to Conectiv Energy and Pepco Energy Services. The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability, and transmission.

     In 2007, Pepco Holdings has increased its projected construction expenditures, excluding the costs associated with the PHI Mid-Atlantic Power Pathway Project (the MAPP Project) and the Blueprint for the Future discussed below, for the five-year period 2007 through 2011 as disclosed in its Form 10-K for the year ended December 31, 2006 by $25 million in 2007, $46 million in 2008, and $4 million in 2009 for the construction by Conectiv Energy of a new combustion turbine power plant.

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     In June, 2007, Conectiv Energy filed its compliance plan as required by the Delaware multipollutant emissions regulations adopted by the Delaware Department of Natural Resources and Environmental Control. The plan includes installation of a sodium based sorbent injection system and a Selective Non-Catalytic Reduction (SNCR) system and carbon injection for Edge Moor Units 3 and 4, and use of an SNCR system and lower sulfur oil at Edge Moor Unit 5. Conectiv Energy believes that with these modifications, it can meet the requirements of the new regulations at an estimated capital cost of $50 to $80 million. The compliance plan filed by Conectiv Energy contemplates capital expenditures of $14 million of capital in 2007 and $25 million of capital in 2008. Pepco Holdings five year construction plan includes projected construction spending of $50 million relating to compliance with the Delaware multipollutant regulations, of which an aggregate of $31 million has been included in i ts construction expenditures for 2007 and 2008.

MAPP Project

     On October 17, 2007, Pepco Holdings received the approval of the PJM Board of Managers to build a new 230-mile, 500-kilovolt interstate transmission line as part of PJM's Regional Transmission Expansion Plan to address the reliability objectives of the PJM system. The transmission line, which is referred to as the MAPP Project, will be located in northern Virginia, Maryland, the Delmarva Peninsula and New Jersey. The preliminarily estimated cost of the 500-kilovolt MAPP Project is approximately $1 billion. Construction is expected to occur in sections over a seven-year period with completion targeted by 2014. PHI also plans to add significant 230-kilovolt support lines in Maryland and New Jersey to connect with the new 500-kilovolt line at an approximate cost of $200 million, which brings the total MAPP Project cost to approximately $1.2 billion. PJM continues to evaluate the 230-kilovolt portion of the project with a decision expected in early 2008. The construction co sts associated with the MAPP Project and additional 230-kilovolt lines are not included in PHI's current projection of construction expenditures as discussed above. PHI expects to fund the expenditures program through a combination of internally generated funds and external financing.

     Blueprint for the Future

     During 2007, the utility subsidiaries of Pepco Holdings announced an initiative referred to as the "Blueprint for the Future." This initiative combines traditional energy efficiency programs with new technologies and systems to help customers manage their energy use and reduce the total cost of energy. The programs include demand side management efforts, such as rebates or other financial incentives for residential customers to replace inefficient appliances and for business customers to use more energy efficient equipment, such as improved lighting and HVAC systems. Under the proposals, customers also could receive credits on their bills for allowing the utility company to "cycle," or intermittently turn off, their central air conditioning or heat pumps when wholesale electricity prices are high. The proposals contemplate that business customers would receive financial incentives for using energy efficient equipment, and would be rewarded for reducing use during pe riods of peak demand. Additionally, Pepco and DPL intend to install "smart meters" for all customers in the District of Columbia, Maryland and Delaware, providing the utilities with the ability to remotely read the meters and identify the location of a power outage.

     Pepco and DPL have made filings with their respective regulatory commissions for approval of certain aspects of these programs. ACE intends to make a filing with the New Jersey Board of

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Public Utilities later in 2007 proposing to implement similar programs in its service territory. The estimated cost to implement these proposals, if approved by the applicable regulatory commissions, is approximately $646 million over the seven-year period from 2008 to 2014. These costs are not included in Pepco Holdings' current projection of construction expenditures as discussed above.

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

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

     As of September 30, 2007, Pepco Holdings and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, performance residual value, and other commitments and obligations. The fair value of these commitments and obligations was not required to be recorded in Pepco Holdings' Consolidated Balance Sheets; however, certain energy marketing obligations of Conectiv Energy were recorded. The commitments and obligations, in millions of dollars, were as follows:

	Guarantor
		PHI		DPL		ACE		Other		Total
Energy marketing obligations of Conectiv Energy (1)	$	192.2	$	-	$	-	$	-	$	192.2
Energy procurement obligations of Pepco Energy Services (1)		92.4		-		-		-		92.4
Guaranteed lease residual values (2)		-		2.7		3.0		.6		6.3
Other (3)		2.5		-		-		1.5		4.0
Total	$	287.1	$	2.7	$	3.0	$	2.1	$	294.9

1.	Pepco Holdings has contractual commitments for performance and related payments of Conectiv Energy and Pepco Energy Services to counterparties related to routine energy sales and procurement obligations, including requirements under BGS contracts entered into by Conectiv Energy with ACE.
2.	Subsidiaries of Pepco Holdings have guaranteed residual values in excess of fair value related to certain equipment and fleet vehicles held through lease agreements. As of September 30, 2007, obligations under the guarantees were approximately $6.3 million. Assets leased under agreements subject to residual value guarantees are typically for periods ranging from 2 years to 10 years. Historically, payments under the guarantees have not been made by the guarantor as, under normal conditions, the contract runs to full term at which time the residual value is minimal. As such, Pepco Holdings believes the likelihood of payment being required under the guarantee is remote.
3.	Other guarantees consist of:

· Pepco Holdings has guaranteed a subsidiary building lease of $2.5 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. As of September 30, 2007, the guarantees cover the remaining $1.5 million in rental obligations.

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     Pepco Holdings and certain of its subsidiaries have entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These indemnification agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Typically, claims may be made by third parties under these indemnification agreements over various periods of time depending on the nature of the claim. The maximum potential exposure under these indemnification agreements can range from a specified dollar amount to an unlimited amount depending on the nature of the claim and the particular transaction. The total maximum potential amount of future payments under these indemnification agreements is not estimable due to several factors, including uncertainty as to whether or when claims may be made under these indemn ities.

     Dividends

     On October 25, 2007, Pepco Holdings' Board of Directors declared a dividend on common stock of 26 cents per share payable December 31, 2007, to shareholders of record on December 10, 2007.

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     Energy Contract Net Asset/Liability Activity

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

Roll-forward of Mark-to-Market Energy Contract Net Liabilities For the Nine Months Ended September 30, 2007 (Dollars are pre-tax and in millions)
	Proprietary Trading (1)	Other Energy Commodity (2)	Total
Total Marked-to-Market (MTM) Energy Contract   Net Liabilities at December 31, 2006	$          -	$(64.3)	$(64.3)
Total change in unrealized fair value	-	15.5	15.5
Reclassification to realized at settlement of contracts	-	49.1	49.1
Effective portion of changes in fair value - recorded      in Other Comprehensive Income	-	(57.1)	(57.1)
Ineffective portion of changes in fair value -      recorded in earnings	-	(1.3)	(1.3)
Total MTM Energy Contract Net Liabilities at September 30, 2007	$          -	(58.1)	(58.1)
Detail of MTM Energy Contract Net Liabilities at September 30, 2007 (see above)			Total
Current Assets (other current assets)			$  19.2
Noncurrent Assets (other assets)			16.0
Total MTM Energy Contract Assets			35.2
Current Liabilities (other current liabilities)			(65.8)
Noncurrent Liabilities (other liabilities)			(27.5)
Total MTM Energy Contract Liabilities			(93.3)
Total MTM Energy Contract Net Liabilities			$(58.1)

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

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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, 2007 and are subject to change as a result of changes in these factors:

Maturity and Source of Fair Value of Mark-to-Market Energy Contract Net Assets (Liabilities) As of September 30, 2007 (Dollars are pre-tax and in millions)
	Fair Value of Contracts at September 30, 2007                           Maturities
Source of Fair Value	2007	2008	2009	2010 and  Beyond	Total Fair Value
Proprietary Trading
Actively Quoted (i.e., exchange-traded) prices	$       -	$       -	$      -	$      -	$      -
Prices provided by other external sources	-	-	-	-	-
Modeled	-	-	-	-	-
Total	$       -	$       -	$      -	$      -	$      -
Other Energy Commodity, net (1)
Actively Quoted (i.e., exchange-traded) prices	$(31.4)	$ 4.4	$  4.6	$    .1	$(22.3)
Prices provided by other external sources (2)	(16.5)	(6.4)	(10.7)	2.4	(31.2)
Modeled (3)	4.7	(4.8)	(4.1)	(.4)	(4.6)
Total	$(43.2)	$(6.8)	$(10.2)	$ 2.1	$(58.1)

Notes:
(1)	Includes all SFAS No. 133 hedge activity and non-proprietary trading activities marked-to-market through Accumulated Other Comprehensive Income or on the Statement of Earnings, as required.
(2)	Prices provided by other external sources reflect information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(3)	This modeled position represents standard offer service and associated supply outside of Conectiv Energy's native Mid-Atlantic Area Council territory in PJM which is receiving fair value accounting with the gains and losses recorded through current income. Pricing for the load portion of the transaction is modeled from broker quotes obtained for the closest trading hub, and adjusted for load following factors and historical congestion. Load volumes are adjusted for expected migration. Anticipated margin (Day 1 gain) on the transaction has been reserved in accordance with Emerging Issues Task Force (EITF) Issue No. 02-3.

     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

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time of the downgrade. As of September 30, 2007, a one-level downgrade in the credit rating of PHI and all of its affected subsidiaries would have required PHI and such subsidiaries to provide an additional $345 million of aggregate cash collateral or letters of credit. PHI believes that it and its utility subsidiaries maintain adequate short-term funding sources in the event the additional collateral or letters of credit are required.

     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, 2007, Pepco Holdings' subsidiaries engaged in Competitive Energy activities and Default Electricity Supply activities provided cash collateral in the amount of $118.5 million in connection with these activities.

REGULATORY AND OTHER MATTERS

Final Resolution of Mirant Bankruptcy Matter

     As previously disclosed in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Relationship with Mirant Corporation" of PHI's Annual Report on Form 10-K for the year ended December 31, 2006 (the PHI 2006 Form 10-K), in 2000, Pepco sold substantially all of its electricity generating assets to Mirant Corporation (formerly Southern Energy, Inc.) and certain of its subsidiaries. In July 2003, Mirant and certain of its subsidiaries filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas (the Bankruptcy Court). In December 2005, the Bankruptcy Court approved the Plan of Reorganization (the Reorganization Plan) of Mirant and the Mirant business emerged from bankruptcy in January 2006, as a new corporation of the same name (together with its predecessors, Mirant).

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

     Power Purchase Agreement

     The Panda PPA obligates Pepco to purchase from Panda 230 megawatts of energy and capacity annually through 2021. At the time of the sale of Pepco's generating assets to Mirant, the purchase price of the energy and capacity under the Panda PPA was, and since that time has continued to be, substantially in excess of the market price. As a part of the Asset Purchase and Sale Agreement, Pepco entered into a "back-to-back" arrangement with Mirant. Under this arrangement, Mirant was obligated through 2021 to purchase from Pepco the capacity and energy that Pepco is obligated to purchase under the Panda PPA at a price equal to Pepco's purchase price from Panda (the PPA-Related Obligations).

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     The SMECO Agreement

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

     Settlement Agreements with Mirant

     In May 2006, Pepco, PHI, and certain affiliated companies entered into a Settlement Agreement and Release (the Settlement Agreement) with Mirant, which settled all outstanding issues between the parties arising from or related to the Mirant bankruptcy, as more fully described below. Separately, Mirant and SMECO entered into a Settlement Agreement and Release (the SMECO Settlement Agreement), which provides that Mirant will assume, rather than reject, the SMECO Agreement. This assumption ensures that Pepco will not incur liability to SMECO as the guarantor of the SMECO Agreement due to the rejection of the SMECO Agreement, although Pepco will continue to guarantee to SMECO the future performance of Mirant under the SMECO Agreement.

     In August 2006, the Bankruptcy Court issued an order approving the Settlement Agreement and the SMECO Settlement Agreement. This order was appealed to the United States District Court for the Northern District of Texas (the District Court) by certain holders of Mirant bankruptcy claims who had objected to approval of the Settlement Agreement and the SMECO Settlement Agreement before the Bankruptcy Court. In December 2006, the District Court issued an order affirming the Bankruptcy Court's order approving the Settlement Agreement and the SMECO Settlement Agreement. In January 2007, the parties that appealed the Bankruptcy Court's order filed a notice of appeal of the District Court's order with the United States Court of Appeals for the Fifth Circuit (the Fifth Circuit). On August 8, 2007, the Fifth Circuit, on the basis of a settlement reached between Mirant and the objecting creditors, issued an order dismissing the appeal with prejudice.

     Under the terms of the Settlement Agreement, Mirant assumed the Asset Purchase and Sale Agreement, except for the PPA-Related Obligations, and Pepco was to receive $520 million, consisting of (i) $450 million in damages as compensation from Mirant for rejecting the PPA-Related Obligations and (ii) $70 million in settlement of other Pepco damage claims against the Mirant bankruptcy estate. To implement the settlement, the following transactions occurred.

· Pepco received from Mirant shares of Mirant stock with an estimated value of $520.0 million, which were liquidated, resulting in net cash proceeds of $522.2 million, after transaction costs.

· Pepco reimbursed Mirant $2.2 million, representing the excess of the amount of the net proceeds of $522.2 million over the settlement amount of $520.0 million.

· Pepco reimbursed Mirant $70.0 million for the amount previously received by Pepco from Mirant in August 2006, which became due in accordance with the terms of the Settlement Agreement as a result of its approval by the Bankruptcy Court. At the time of

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	receipt, Pepco did not recognize any portion of the payment in earnings pending the appeal of the Bankruptcy Court order.
·	Pepco reimbursed Mirant $36.1 million, representing the net above-market costs paid by Mirant under the Panda PPA "back-to-back" arrangement during the period from June 1, 2006, the date the parties entered into the Settlement Agreement, to August 8, 2007, the date the objecting creditors' appeal was dismissed by the Fifth Circuit.

     In addition, under the Settlement Agreement, all pending appeals, adversary actions and other contested matters between Pepco and Mirant were dismissed with prejudice and each party released the other from any and all claims relating to the Mirant bankruptcy.

     Pepco intends to use the $413.9 million of the settlement payment (the $450 million portion, less the $36.1 million that Pepco has reimbursed to Mirant), plus interest earned, to pay for future above-market capacity and energy purchases under the Panda PPA over the remaining life of the Panda PPA through 2021. The $413.9 million is being accounted for as non-current restricted cash, and a corresponding non-current regulatory liability has been recorded, based on Pepco's expectation that both the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC) will issue orders directing Pepco to use the proceeds, and any earnings on the proceeds, solely to offset the future above-market costs. Management intends to seek these orders from the DCPSC and the MPSC in the fourth quarter of 2007.

     Of the $70.0 million received in settlement of other Pepco damage claims, $33.4 million has been recorded as a reduction of operating expenses, $21.0 million has been recorded as a reduction in a net pre-petition receivable claim from Mirant, $15.0 million has been recorded as a reduction in the capitalized costs of certain property plant and equipment and the remaining $.6 million has been recorded as a liability to reimburse SMECO for certain legal costs associated with the settlement.

Rate Proceedings

     Delaware

     On September 4, 2007, DPL submitted its 2007 GCR filing to the Delaware Public Service Commission (DPSC). On September 18, 2007, the DPSC issued an initial order approving a 5.7% decrease in the level of the GCR, which will become effective November 1, 2007, subject to refund and pending final DPSC approval after evidentiary hearings.

ACE Restructuring Deferral Proceeding

     For a discussion of the history of the ACE restructuring deferral proceeding in New Jersey, please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Rate Proceedings -- ACE Restructuring Deferral Proceeding" of the PHI 2006 Form 10-K. On August 9, 2007, the Appellate Division of the Superior Court of New Jersey (the Appellate Division), citing deference to the factual and policy findings of the NJBPU, affirmed the NJBPU's decision in its entirety, rejecting challenges from ACE and the Division of Rate Counsel. On September 10, 2007, ACE filed an application for certification to the New Jersey Supreme Court. Though ACE continues to believe that the

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position it took before the Appellate Division is correct, there is no assurance that the New Jersey Supreme Court will agree to hear this discretionary appeal.

Divestiture Cases

     New Jersey

     For a discussion of the history of the New Jersey divestiture case proceeding, please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Divestiture Cases -- New Jersey" of the PHI 2006 Form 10-K and Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Divestiture Cases -- New Jersey " of PHI's Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (the PHI 2^nd Quarter Form 10-Q). On October 24, 2007, the NJBPU approved a stipulation resolving the accumulated deferred Federal income taxes (ADFIT) issue and issued a clarifying order, which concludes that the $94.8 million in stranded cost reduction, including the $54.1 million in ADFIT, does not violate the Internal Revenue Service (IRS) normalization rules. In explaining this result, the NJBPU stated that (i) its earli er orders determining ACE's recoverable stranded costs "net of tax" did not cause ADFIT associated with certain divested nuclear assets to reduce stranded costs otherwise recoverable from ACE's ratepayers, and (ii) because the Market Transition Charge-Tax component of the stranded cost recovery was intended by the NJBPU to gross-up "net of tax" stranded costs, thereby ensuring and establishing that the ADFIT balance was not flowed through to ratepayers, the normalization rules were not violated.

Default Electricity Supply Proceedings

     Virginia

     As previously disclosed in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Default Electricity Supply Proceedings -- Virginia" of the PHI 2^nd Quarter Form 10-Q, pursuant to an order dated June 8, 2007, the Virginia State Corporation Commission (VSCC) denied DPL's July 1, 2007 rate increase request, based on its conclusion that the provisions of the Memorandum of Understanding (which DPL entered into with the staff of the VSCC in connection with the approval of DPL's divestiture of its generation assets in 2000) relating to fuel costs did not end effective June 30, 2007. As a result of this decision, DPL under-recovered its cost of providing Default Service by approximately $1.9 million between June 1, 2007 and the September 30, 2007 expiration of the Default Service contract. Any further under-recovery will be determined by the difference between the fuel proxy rate calculation and market rates for the fuel portion of Default Service and the timing of completion of the sale of DPL's Virginia electric operations as described below under the heading "DPL Sale of Virginia Operations." A fixed price, partial hedge has been purchased for the period through December 31, 2007, which should substantially limit DPL's exposure to market price fluctuations during that period.

     DPL filed a complaint for a declaratory order and preliminary injunctive relief with the U.S. District Court for the Eastern District of Virginia (the Virginia District Court). On July 23, 2007, the Virginia District Court dismissed the complaint and denied injunctive relief, finding that the court lacked subject matter jurisdiction and stating that even if it had subject matter

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jurisdiction, it would abstain from exercising that jurisdiction to allow the Supreme Court of Virginia to consider the issues upon which the complaint was based.

     DPL currently is pursuing relief in both state and federal courts: On July 31, 2007, DPL filed a notice of appeal of the VSCC's orders with the Supreme Court of Virginia; and on August 31, 2007, DPL filed an appeal from the Virginia District Court's order with the U. S. Court of Appeals for the Fourth Circuit. The sale of DPL's Virginia electric operations as described below under the heading "DPL Sale of Virginia Operations" is not contingent upon resolution of any of the matters that are at issue in these proceedings. If the sale of the Virginia electric operations is completed, the effect, if any, on these proceedings is not determinable at this time.

ACE Sale of B.L. England Generating Facility

     As previously disclosed in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- ACE Sale of B.L. England Generating Facility" of the PHI 2006 Form 10-K, on February 8, 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy Investments, LLC, for which it received proceeds of approximately $9 million, after giving effect to certain post-closing adjustments. At the time of the sale, RC Cape May and ACE agreed to submit to arbitration the issue of whether RC Cape May, under the terms of the purchase agreement, must pay to ACE an additional $3.1 million as part of the purchase price. Arbitration hearings were held October 15 through 17, 2007. An oral argument is scheduled for January 15, 2008, and a decision by the arbitrators is expected in February 2008. As part of the sale, RC Cape May assume d certain liabilities associated with the B.L. England generating station, including substantially all environmental liabilities.

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

     The sale of B.L. England will not affect the stranded costs associated with the plant that already have been securitized. ACE anticipates that approximately $9 million to $10 million of additional regulatory assets related to B.L. England may, subject to NJBPU approval, be eligible for recovery as stranded costs. Approximately $47 million in emission allowance credits associated with B. L. England were monetized for the benefit of ACE's ratepayers pursuant to the NJBPU order approving the sale. Net proceeds from the sale of the plant and monetization of the emission allowance credits, will be credited to ACE's ratepayers in accordance with the requirements of EDECA and NJBPU orders. The appropriate mechanism for crediting the net proceeds from the sale of the plant and the monetized emission allowance credits to ratepayers is being determined in a Phase II proceeding which is currently pending before the NJBPU.

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DPL Sale of Virginia Operations

     For a discussion of the history of DPL's sale of its Virginia operations, please refer to Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- DPL Sale of Virginia Operations" of the PHI 2^nd Quarter Form 10-Q. On October 9, 2007, FERC granted approval of an interconnection agreement and a facilities agreement needed for the completion of the sale transaction with Old Dominion Electric Cooperative (ODEC). On October 19, 2007, the VSCC issued an order approving both the transactions with ODEC and the transaction with A&N Electric Cooperative (A&N). Northern Virginia Electric Cooperative (NOVAC) intervened in the VSCC proceedings, opposing the DPL sales to A&N and ODEC. NOVAC may file a petition for reconsideration within 20 days of the order. They also may appeal the VSCC order within 30 days. If filed, this would be considered an appeal "of right,"which means the Virginia Supreme Court must hear the appeal.

Cash Balance Plan Litigation

     For a discussion of the history of the Cash Balance Plan litigation, please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Cash Balance Plan Litigation " of the PHI 2006 Form 10-K and Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Cash Balance Plan Litigation " of PHI's Quarterly Report for the Quarter Ended March 31, 2007 (the PHI 1^st Quarter Form 10-Q). As previously disclosed, the PHI Retirement Plan, PHI and Conectiv filed a motion for summary judgment at the close of discovery. This motion was granted by the U.S. District Court for the District of Delaware on September 19, 2007. On October 12, 2007, the plaintiffs filed an appeal of the decision to the U.S. Court of Appeals for the Third Circuit.

Environmental Litigation

     Cambridge, Maryland Site. For a discussion of the history of the environmental proceedings at the Cambridge, Maryland site, please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Environmental Litigation " of the PHI 2006 Form 10-K. The costs of cleanup (as determined by the Remedial Investigation/Feasibility Study and subsequent negotiations with the Maryland Department of the Environment) are anticipated to be approximately $3.5 million. The final cleanup costs will include protective measures to control contaminant migration during the dredging activities and improvements to the existing shoreline dock.

     Delilah Road Landfill Site. For a discussion of the history of the environmental proceedings at the Delilah Road Landfill site, please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Environmental Litigation " of the PHI 2006 Form 10-K and Item 2, "Management's Discussion -- and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters  Environmental Litigation" of both the PHI 1^st Quarter Form 10-Q and the PHI 2^nd Quarter Form 10-Q. In August 2007, the group of potentially responsible parties (PRPs) in connection with this site agreed to reimburse the costs of the United States 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) and in October 2007, EPA and the PRP group entere d

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into a tolling agreement to permit the parties sufficient time to execute a final settlement agreement. This settlement agreement will allow the EPA to reopen the settlement in the event of new information or unknown conditions at the site.

     Frontier Chemical Site. For a discussion of the history of the environmental proceedings at the Frontier Chemical site, please refer to Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Environmental Litigation " of the PHI 2^nd Quarter Form 10-Q. In October 2007, ACE entered into an agreement with the other PRPs at this site to form a PRP group.

     Deepwater Generating Station. For a discussion of the history of the environmental proceedings at Deepwater Generating Station, please refer to Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Environmental Litigation " of both the PHI 1^st Quarter Form 10-Q and the PHI 2^nd Quarter Form 10-Q. On October 2, 2007, the New Jersey Office of Administrative Law (OAL) issued a decision granting summary decision in favor of Conectiv Energy, finding that hourly heat input shall not be used as a condition or limit for Conectiv Energy's electric generating operations. On October 16, 2007, the New Jersey Department of Environmental Protection (NJDEP) requested that the commissioner of the NJDEP review and reject the OAL decision on an interlocutory basis. In its October 19, 2007 response, Conectiv Energy requested that the commissioner deny NJDEP's request for interlocutory re view.

     Carll's Corner Generating Station. For a discussion of the history of the environmental proceedings at Carll's Corner Generating Station, please refer to Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- Environmental Litigation " of both the PHI 1^st Quarter Form 10-Q and the PHI 2^nd Quarter Form 10-Q. On August 31, 2007, Conectiv Energy executed a settlement agreement with NJDEP, under which NJDEP determined the violation had been corrected, and Conectiv Energy agreed to operate in compliance with all applicable regulations and permits and paid a penalty of $55,000.

Federal Tax Treatment of Cross-border Leases

     PCI maintains a portfolio of cross-border energy sale-leaseback transactions, which, as of September 30, 2007, had a book value of approximately $1.4 billion.

     On February 11, 2005, the Treasury Department and IRS issued Notice 2005-13 informing taxpayers that the IRS intends to challenge on various grounds the purported tax benefits claimed by taxpayers entering into certain sale-leaseback transactions with tax-indifferent parties (i.e., municipalities, tax-exempt and governmental entities) (the Notice). In addition, on June 29, 2005 the IRS published a Coordinated Issue Paper concerning the resolution of audit issues related to such transactions. PCI's cross-border energy leases are similar to those sale-leaseback transactions described in the Notice and the Coordinated Issue Paper.

     PCI's leases have been under examination by the IRS as part of the normal PHI tax audit. On June 9, 2006, the IRS issued its final revenue agent's report (RAR) for its audit of PHI's 2001 and 2002 income tax returns. In the RAR, the IRS disallowed the tax benefits claimed by PHI with respect to certain of these leases for those years. The tax benefit claimed by PHI with respect to the leases under audit is approximately $60 million per year and from 2001 through

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September 30, 2007 were approximately $332 million. PHI has filed a protest against the IRS adjustments and the unresolved audit has been forwarded to the Appeals Office. The ultimate outcome of this issue is uncertain; however, if the IRS prevails, PHI would be subject to additional taxes, along with interest and possibly penalties on the additional taxes, which could have a material adverse effect on PHI's financial condition, results of operations, and cash flows. PHI believes that its tax position related to these transactions was appropriate based on applicable statutes, regulations and case law, and intends to contest the adjustments proposed by the IRS; however, there is no assurance that PHI's position will prevail.

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

IRS Mixed Service Cost Issue

     For a discussion of the IRS claim relating to capitalization by Pepco, DPL and ACE of certain construction costs for income tax purposes, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations -- Regulatory and Other Matters -- IRS Mixed Service Cost Issue in Pepco Holdings' Annual Report on Form 10-K for the year ended December 31, 2006.

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, 2006. No material changes to Pepco Holdings' critical accounting policies occurred during the third quarter of 2007.

NEW ACCOUNTING STANDARDS

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

     In March 2006, the FASB issued FSP FASB Technical Bulletin (FTB) 85-4-1, "Accounting for Life Settlement Contracts by Third-Party Investors" (FSP FTB 85-4-1). This FSP provides initial and subsequent measurement guidance and financial statement presentation and disclosure guidance for investments by third-party investors in life settlement contracts. FSP FTB 85-4-1 also amends certain provisions of FTB No. 85-4, "Accounting for Purchases of Life Insurance," and SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The guidance in FSP FTB 85-4-1 applies prospectively for all new life settlement contracts and is effective for fiscal years beginning after June 15, 2006 (year ending December 31, 2007 for

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Pepco Holdings). Implementation of FSP FTB 85-4-1 did not have a material impact on Pepco Holdings' overall financial condition, results of operations, or cash flows.

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

     In February 2006, the FASB issued SFAS No. 155, "Accounting for Certain Hybrid Financial Instruments - an amendment of FASB Statements No. 133 and 140" (SFAS No. 155). SFAS No. 155 amends SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," and SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." SFAS No. 155 resolves issues addressed in Statement 133 Implementation Issue No. D1, "Application of Statement 133 to Beneficial Interests in Securitized Financial Assets." SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity's first fiscal year that begins after September 15, 2006 (year ending December 31, 2007 for Pepco Holdings). Implementation of SFAS No. 155 did not have a material impact on Pepco Holdings' overall financial condition, results of operations, or cash flows.

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

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

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

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

     On June 28, 2006, the FASB ratified EITF Issue No. 06-3, "Disclosure Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing Transactions" (EITF 06-3). EITF 06-3 provides guidance on an entity's disclosure of its accounting policy regarding the gross or net presentation of certain taxes and provides that if taxes included in gross revenues are significant, a company should disclose the amount of such taxes for each period for which an income statement is presented (i.e., both interim and annual periods). Taxes within the scope of EITF 06-3 are those that are imposed on and concurrent with a specific revenue-producing transaction. Taxes assessed on an entity's activities over a period of time are not within the scope of EITF 06-3. Pepco Holdings implemented EITF 06-3 during the first quarter of 2007. Taxes

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included in Pepco Holdings gross revenues were $89.7 million and $76.0 million for the three months ended September 30, 2007 and 2006, respectively, and $239.8 million and $201.3 million for the nine months ended September 30, 2007 and 2006, respectively.

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

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

     FSP FAS 13-2 is effective for the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for Pepco Holdings). A material change in the timing of cash flows under Pepco Holdings' cross-border leases as the result of a settlement with the Internal Revenue Service or a change in tax law would require an adjustment to the book value of the leases and a charge to earnings equal to the repricing impact of the disallowed deductions which could result in a material adverse effect on its overall financial condition, results of operations, and cash flows. For a further discussion, see "Federal Tax Treatment of Cross-border Leases" in Note (4), "Commitments and Contingencies."

     SFAS No. 157, "Fair Value Measurements"

     In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" (SFAS No. 157) which defines fair value, establishes a framework for measuring fair value in conformity with accounting principles generally accepted in the United States of America (GAAP), and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of this Statement will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the disclosures about fair value measurements.

     SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years (year ending December 31, 2008 for Pepco Holdings). Pepco Holdings is currently in the process of evaluating the impact that SFAS No. 157 will have on its overall financial condition, results of operations, and cash flows.

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

     On September 8, 2006, the FASB issued FSP American Institute of Certified Public Accountants Industry Audit Guide, Audits of Airlines--"Accounting for Planned Major Maintenance Activities" (FSP AUG AIR-1), which prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods for all industries. FSP AUG AIR-1 is effective the first fiscal year beginning after December 15, 2006 (year ending December 31, 2007 for Pepco Holdings). Implementation of FSP AUG AIR-1 did not have a material impact on Pepco Holdings' overall financial condition, results of operations, or cash flows.

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

     On September 20, 2006, the FASB ratified EITF Issue No. 06-5, "Accounting for Purchases of Life Insurance -- Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of Life Insurance" (EITF 06-5) which provides guidance on whether an entity should consider the contractual ability to surrender all of the individual-life policies (or certificates under a group life policy) together when determining the amount that could be realized in accordance with FTB 85-4, and whether a guarantee of the additional value associated with the group life policy affects that determination. EITF 06-5 provides that a policyholder should (i) determine the amount that could be realized under the insurance contract assuming the surrender of an individual-life by individual-life policy (or certificate by certificate in a group policy) and (ii) not discount the cash surrender value component of the amount that could be realized when c ontractual restrictions on the ability to surrender a policy exist unless contractual limitations prescribe that the cash surrender value component of the amount that could be realized is a fixed amount, in which case the amount that could be realized should be discounted in accordance with Accounting Principles Board of the American Institute of Certified Public Accountants Opinion 21. EITF 06-5 is effective for fiscal years beginning after December 15, 2006 (year ending December 31, 2007 for Pepco Holdings). Implementation of EITF 06-5 did not have a material impact on Pepco Holdings' overall financial condition, results of operations, cash flows, or footnote disclosure requirements.

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

     On December 21, 2006, the FASB issued FSP No. EITF 00-19-2, "Accounting for Registration Payment Arrangements" (FSP EITF 00-19-2), which addresses an issuer's accounting for registration payment arrangements and specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with SFAS No. 5, "Accounting for Contingencies." FSP EITF 00-19-2 is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to the date of its issuance. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to the issuance of FSP EITF 00-19-2, this guidance is effective for f inancial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years (year ending December 31, 2007 for Pepco Holdings). Pepco Holdings implemented FSP EITF 00-19-2 during the first quarter of 2007. The implementation did not have a material impact on its overall financial condition, results of operations, or cash flows.

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

     On February 15, 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115" (SFAS No. 159) which permits entities to elect to measure eligible financial instruments at fair value. The objective of SFAS No. 159 is to improve financial reporting by providing entities with the

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opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. However, it is possible that the application of SFAS No. 159 will change current practice with respect to the definition of fair value, the methods used to measure fair value, and the disclosures about fair value measurements.

   SFAS No. 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company's choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. SFAS No. 159 does not eliminate disclosure requirements included in other accounting standards.

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

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

     On April 30, 2007, the FASB issued FSP FIN 39-1, "Amendment of FASB Interpretation No. 39" to amend certain portions of Interpretation 39. The FSP replaces the terms "conditional contracts" and "exchange contracts" in Interpretation 39 with the term "derivative instruments" as defined in Statement 133. The FSP also amends Interpretation 39 to allow for the offsetting of fair value amounts for the right to reclaim cash collateral or receivable, or the obligation to return cash collateral or payable, arising from the same master netting arrangement as the derivative instruments. FSP FIN 39-1 applies to fiscal years beginning after November 15, 2007 (year ending December 31, 2008 for Pepco Holdings), with early adoption permitted. Pepco Holdings has evaluated the impact of FSP FIN 39-1 and has determined that it does not have a material impact on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

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

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

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benefit from dividends on those awards should be included in the pool of excess tax benefits available to absorb tax deficiencies on share-based payment awards (i.e. the "APIC pool").

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

     EITF Issue No. 06-11 applies prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years beginning after December 15, 2007, and interim periods within those fiscal years (year ending December 31, 2008 for Pepco Holdings). Early application is permitted as of the beginning of a fiscal year for which interim or annual financial statements have not yet been issued. Retrospective application to previously issued financial statements is prohibited. Entities must disclose the nature of any change in their accounting policy for income tax benefits of dividends on share-based payment awards resulting from the adoption of this guidance. Pepco Holdings is currently in the process of evaluating the impact that EITF Issue No. 06-11 will have on its overall financial condition, results of operations, cash flows and footnote disclosure requirements.

FORWARD-LOOKING STATEMENTS

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

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

· 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;

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· 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 (NY ISO, ISO New England), the North American Electric Reliability Council and other applicable electric reliability organizations;

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

· Pace of entry into new markets;

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

· Interest rate fluctuations and credit market concerns; and

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

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

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

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

POTOMAC ELECTRIC POWER COMPANY

GENERAL OVERVIEW

     Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in Washington, D.C. and major portions of Montgomery County and Prince George's County in suburban Maryland. Pepco provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier, in both the District of Columbia and Maryland. Default Electricity Supply is known as Standard Offer Service (SOS) in both the District of Columbia and Maryland. Pepco's service territory covers approximately 640 square miles and has a population of approximately 2.1 million. As of September 30, 2007, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to Washington, D.C. customers.

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

RESULTS OF OPERATIONS

     The accompanying results of operations discussion is for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006. 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.

Operating Revenue

	2007		2006		Change
Regulated T&D Electric Revenue	$	705.4	$	666.2	$	39.2
Default Supply Revenue		966.3		1,049.4		(83.1)
Other Electric Revenue		23.5		22.4		1.1
Total Operating Revenue	$	1,695.2	$	1,738.0	$	(42.8)

     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 Pepco receives for delivery of electricity to its customers for which Pepco is paid regulated rates. Default Supply Revenue is the revenue received from Default Electricity Supply. The costs related to the supply of electricity are included in Fuel and Purchased Energy expense. Other Electric Revenue includes work and services performed on behalf of customers including other utilities, which is not subject to price

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regulation. Work and services includes mutual assistance to other utilities, highway relocation, rents, late payments, and collection fees.

     Regulated T&D Electric

Regulated T&D Electric Revenue	2007		2006		Change
Residential	$	207.8	$	197.2	$	10.6
Commercial		401.6		385.7		15.9
Industrial		-		-		-
Other (Includes PJM)		96.0		83.3		12.7
Total Regulated T&D Electric Revenue	$	705.4	$	666.2	$	39.2

Regulated T&D Electric Sales (gigawatt hours (GWh))	2007		2006		Change
Residential		6,332		6,048		284
Commercial		14,532		14,203		329
Industrial		-		-		-
Other		114		115		(1)
Total Regulated T&D Electric Sales		20,978		20,366		612

Regulated T&D Electric Customers (000s)	2007		2006		Change
Residential		683		676		7
Commercial		73		73		-
Industrial		-		-		-
Other		-		-		-
Total Regulated T&D Electric Customers		756		749		7

     Regulated T&D Electric Revenue increased by $39.2 million primarily due to the following: (i) $20.9 million increase due to higher weather-related sales (a 20% increase in Heating Degree Days and a 13% increase in Cooling Degree Days), (ii) $15.4 million increase in Other Regulated T&D Electric Revenue due to a change in the accounting for the resale of energy and capacity purchased under a power purchase agreement with Panda-Brandywine LLP, an independent power producer (Panda PPA) in the PJM Interconnection, LLC(PJM) market, which by reason of the existence of the "back-to-back" arrangement with Mirant, which terminated in August 2007, was not previously recorded as revenue (offset in Fuel and Purchased Energy) , (iii) $6.7 million increase due to higher pass-through revenue resulting from rate increases (offset in Other Taxes), (iv) $2.8 million increase primarily due to increased distribution rates in Maryland beginning in June 2007, (v ) $2.7 million increase due to the effect of the Maryland bill stabilization adjustment (BSA) mechanism implemented in August 2007, (vi) $2.0 million increase due to customer growth of 1.0% in 2007, partially offset by (vii) $5.9 million decrease due to differences in consumption among the various customer rate classes, and (viii) $5.4 million decrease in network transmission revenues primarily due to a decrease in the FERC formula rate in June 2006.

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     Default Electricity Supply

Default Supply Revenue	2007		2006		Change
Residential	$	603.6	$	468.5	$	135.1
Commercial		356.5		578.6		(222.1)
Industrial		-		-		-
Other (Includes PJM)		6.2		2.3		3.9
Total Default Supply Revenue	$	966.3	$	1,049.4	$	(83.1)

Default Electricity Supply Sales (GWh)	2007		2006		Change
Residential		6,016		5,708		308
Commercial		3,383		6,769		(3,386)
Industrial		-		-		-
Other		35		30		5
Total Default Electricity Supply Sales		9,434		12,507		(3,073)

Default Electricity Supply Customers (000s)	2007		2006		Change
Residential		657		647		10
Commercial		53		56		(3)
Industrial		-		-		-
Other		-		-		-
Total Default Electricity Supply Customers		710		703		7

     Default Supply Revenuedecreased by $83.1 million primarily due to the following: (i) $240.2 million decrease primarily due to an increase in commercial customers electing to purchase electricity from competitive suppliers, (ii) $54.4 million decrease due to differences in consumption among the various customer rate classes, partially offset by (iii) $175.9 million increase in higher retail energy rates, primarily resulting from new annual market-based rates, and (iv) $35.6 million increase due to higher weather-related sales, (a 20% increase in Heating Degree Days and a 13% increase in Cooling Degree Days in 2007) (partially offset in Fuel and Purchased Energy).

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

	2007		2006
Sales to DC customers served by Pepco		36%		60%
Sales to MD customers served by Pepco		52%		62%

Operating Expenses

     Fuel and Purchased Energy

     Fuel and Purchased Energy which is primarily associated with Default Electric Supply sales, decreased by $57.9 million to $964.8 million in 2007, from $1,022.7 in 2006. The decrease is

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primarily due to the following: (i) $278.9 million decrease primarily due to an increase in commercial customers electing to purchase electricity from competitive suppliers, (ii) $13.8 million decrease in the Default Electricity Supply deferral balance (partially offset by Default Supply Revenue), partially offset by (iii) $181.0 million increase in average energy costs, the result of new annual SOS supply contracts, (iv) $37.3 million increase due to higher weather-related sales, and (v) $15.4 million increase due to the change in accounting for energy and capacity purchases under the Panda PPA due to a termination of the "back-to-back" arrangement with Mirant (offset in Regulated T&D Electric Revenue).

     Other Operation and Maintenance

    Other Operation and Maintenance increased by $6.4 million to $220.7 million in 2007 from $214.3 million in 2006. The increase was primarily due to the following: (i) $3.4 million increase in employee related costs, (ii) $3.3 million increase in regulatory expenses, (iii) $3.1 million increase due to construction project write-offs related to customer requested work, (iv) $1.2 million increase in business support costs primarily customer services and accounting, partially offset by (v) $2.7 million decrease in company-owned life insurance expenses due to an adjustment in 2006, (vi) $1.2 million decrease in Default Electricity Supply costs (partially deferred and recoverable), and (vii) $1.1 million decrease primarily due to the reclassification of rate case costs to be recovered in future periods in accordance with the June 2007 Maryland rate order.

     Depreciation and Amortization

    Depreciation and Amortization expensesdecreased by $6.7 million to $116.9 million in 2007 from $123.6 million primarily due to a change in depreciation rates in accordance with the June 2007 Maryland rate.

     Effect of Settlement of Mirant Bankruptcy Claims

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

      Other Taxes

     Other Taxes increased $14.2 million to $220.3 million in 2007 from $206.1 million in 2006 primarily due to increased pass-throughs resulting from higher electricity sales and rate increases in the District of Columbia (partially offset in Regulated T&D Electric Revenue).

Other Income (Expenses)

     Other Expenses (which are net of other income) increased by $2.5 million to a net expense of $45.4 million in 2007 from a net expense of $42.9 million in 2006. This increase was primarily due to a $2.1 million gain on a company-owned life insurance policy in 2006.

Income Tax Expense

     Pepco's effective tax rate for the nine months ended September 30, 2007 was 31% as compared to the Federal statutory rate of 35%. The major reasons for the difference between the effective tax rate and the statutory tax rate were the Maryland state refund (net of Federal

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benefit), the flow-through of deferred investment tax credits and certain asset removal costs, partially offset by state income taxes (net of Federal benefit), a deferred tax adjustment and the flow-through of certain book versus tax depreciation differences.

     Pepco's effective tax rate for the nine months ended September 30, 2006 was 39% as compared to the Federal statutory rate of 35%. The major reason for the difference between the effective tax rate and the statutory tax rate were state income taxes (net of Federal benefit) and the flow-through of certain book versus tax depreciation differences, partially offset by changes in estimates related to tax liabilities of prior tax years subject to audit, the flow-through of deferred investment tax credits, and certain asset removal costs.

Capital Requirements

Construction Expenditures

     Pepco's construction expenditures for the nine months ended September 30, 2007, totaled $194.3 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. For the five year period 2007 through 2011, Pepco's currently projected construction expenditures, excluding the costs associated with the PHI Mid-Atlantic Power Pathway Project (the MAPP Project) and the Blueprint for the Future discussed below, are as follows:

	For the Year (in millions)
	2007	2008	2009	2010	2011	Total
Base construction expenditures	$274(a)	$237	$204	$231	$288	$1,234

     (a)     Includes the $194.3 million expended through September 30, 2007, excluding $15.0 million of reimbursements related to the settlement of the Mirant bankruptcy claims.

     Pepco expects to fund these expenditures, and the expenditures associated with the MAPP Project and the Blueprint for the Future, through internally generated cash and from external financing and capital contributions from PHI.

MAPP Project

     On October 17, 2007, Pepco Holdings received the approval of the PJM Board of Managers to build a new 230-mile, 500-kilovolt interstate transmission line as part of PJM's Regional Transmission Expansion Plan to address the reliability objectives of the PJM system. The transmission line, which is referred to as the MAPP Project, will be located in northern Virginia, Maryland, the Delmarva Peninsula and New Jersey. The preliminarily estimated cost of the 500-kilovolt MAPP Project is approximately $1 billion. Construction is expected to occur in sections over a seven-year period with completion targeted by 2014. PHI also plans to add significant 230-kilovolt support lines in Maryland and New Jersey to connect with the new 500-kilovolt line at an approximate cost of $200 million, which brings the total MAPP Project cost to approximately $1.2 billion. The construction costs associated with the MAPP Project and additional 230-kilovolt lines are not included in PHI's current pr ojection of construction expenditures as discussed above. PHI expects to fund the expenditures program through a combination of internally generated funds and external financing.

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     Pepco's portion of the preliminarily estimated cost of the 500-kilovolt MAPP Project is approximately $170 million over a projected five-year construction period beginning in 2008.

Blueprint for the Future

     During 2007, PHI announced an initiative in Pepco's service territory referred to as the "Blueprint for the Future." This initiative combines traditional energy efficiency programs with new technologies and systems to help customers manage their energy use and reduce the total cost of energy, including the installation of "smart meters" for all customers in the District of Columbia and Maryland.

     Pepco has made filings with the District of Columbia Public Service Commission and the MPSC for approval of certain aspects of these programs. Pepco's preliminarily estimated cost to implement these proposals, if approved by the applicable regulatory commissions, is approximately $270 million over the seven-year period from 2008 to 2014.

FORWARD-LOOKING STATEMENTS

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

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

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

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

· Weather conditions;

· Population growth rates and demographic patterns;

· Competition for retail and wholesale customers;

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

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

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

· Changes in project costs;

· Unanticipated changes in operating expenses and capital expenditures;

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

· Restrictions imposed by 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;

· Interest rate fluctuations and credit market concerns; and

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

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

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

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

DELMARVA POWER & LIGHT COMPANY

GENERAL OVERVIEW

     Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and Virginia. DPL provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is also known as Default Service in Virginia, as Standard Offer Service (SOS) in Maryland and Delaware on and after May 1, 2006, and as Provider of Last Resort service in Delaware before May 1, 2006. DPL's electricity distribution service territory covers approximately 6,000 square miles and has a population of approximately 1.3 million. As of September 30, 2007, approximately 65% of delivered electricity sales were to Delaware customers, approximately 32% were to Maryland customers, and approximately 3% were to Virginia customers. DPL also provides natural gas distribution service in northern Delaware. DPL's natural gas distribution service territory covers approximately 275 square miles and has a population of approximately .5 million.

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

RESULTS OF OPERATIONS

     The accompanying results of operations discussion is for the nine months ended September 30, 2007, compared to the nine months ended September 30, 2006. Other than this disclosure, information under this item has been omitted in accordance with General Instruction H to the Form 10-Q. All amounts in the tables (except sales and customers) are in millions.

Electric Operating Revenue

	2007		2006		Change
Regulated T&D Electric Revenue	$	252.2	$	258.8	$	(6.6)
Default Supply Revenue		662.0		633.1		28.9
Other Electric Revenue		15.6		16.9		(1.3)
Total Electric Operating Revenue	$	929.8	$	908.8	$	21.0

     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 DPL receives for delivery of electricity to its customers, for which DPL is paid regulated rates. Default Supply Revenue is the revenue received from Default Electricity Supply. The costs related to the supply of electricity are

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

     Regulated T&D Electric

Regulated T&D Electric Revenue	2007		2006		Change
Residential	$	125.7	$	125.8	$	(.1)
Commercial		67.9		67.7		.2
Industrial		9.0		12.2		(3.2)
Other (Includes PJM)		49.6		53.1		(3.5)
Total Regulated T&D Electric Revenue	$	252.2	$	258.8	$	(6.6)

Regulated T&D Electric Sales (gigawatt hours (GWh))	2007		2006		Change
Residential		4,159		4,050		109
Commercial		4,173		4,080		93
Industrial		2,133		2,187		(54)
Other		38		37		1
Total Regulated T&D Electric Sales		10,503		10,354		149

Regulated T&D Electric Customers (000s)	2007		2006		Change
Residential		455		453		2
Commercial		61		60		1
Industrial		1		1		-
Other		1		1		-
Total Regulated T&D Electric Customers		518		515		3

     Regulated T&D Electric Revenue decreased by $6.6 million primarily due to the following: (i) $10.0 million decrease due to a change in Delaware rate structure effective May 1, 2006, which shifted revenue from Regulated T&D Electric Revenue to Default Supply Revenue, (ii) $4.8 million decrease in network transmission revenues primarily due to a decrease in the FERC formula rate in June 2006, (iii) $4.0 million decrease due to a Delaware base rate reduction in May 2006, (iv) $3.9 million decrease due to differences in consumption among the various customer rate classes, partially offset by (v) $6.8 million increase due to higher weather-related sales (a 17% increase in Heating Degree Days and a 5% increase in Cooling Degree Days), (vi) $4.1 million increase due to an adjustment to reclassify market-priced supply revenue to Default Supply Revenue in 2006, (vii) $4.0 million increase primarily due to increased distribution rates in Maryland beginning in June 2007, and (v iii) $1.2 million increase due to the effect of the Maryland bill stabilization adjustment (BSA) mechanism implemented in August 2007.

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     Default Electricity Supply

Default Supply Revenue	2007		2006		Change
Residential	$	437.4	$	336.5	$	100.9
Commercial		186.3		246.6		(60.3)
Industrial		31.7		46.5		(14.8)
Other (Includes PJM)		6.6		3.5		3.1
Total Default Supply Revenue	$	662.0	$	633.1	$	28.9

Default Electricity Supply Sales (GWh)	2007		2006		Change
Residential		4,108		4,042		66
Commercial		1,759		2,923		(1,164)
Industrial		419		861		(442)
Other		34		37		(3)
Total Default Electricity Supply Sales		6,320		7,863		(1,543)

Default Electricity Supply Customers (000s)	2007		2006		Change
Residential		450		451		(1)
Commercial		53		54		(1)
Industrial		-		-		-
Other		1		1		-
Total Default Electricity Supply Customers		504		506		(2)

     Default Supply Revenue increased by $28.9 million primarily due to the following: (i) $114.4 million increase in higher retail energy rates, primarily resulting from new annual market based rates, (ii) $14.6 million increase due to higher weather-related sales (a 17% increase in Heating Degree Days and a 5% increase in Cooling Degree Days), (iii) $10.0 million increase due to a change in Delaware rate structure effective May 1, 2006 that shifted revenue from Regulated T&D Electric Revenue to Default Supply Revenue, (iv) $1.4 million increase in network transmission revenues due to a change in PJM Interconnection, LLC(PJM) transmission rates, partially offset by (v) $65.6 million decrease primarily due to an increase in commercial and industrial customers electing to purchase electricity from competitive suppliers, (vi) $41.8 million decrease due to differences in consumption among the various customer rate classes, and (vii) $4.1 million decrea se due to an adjustment to reclassify market-priced supply revenue from Regulated T&D Electric Revenue in 2006.

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

	2007		2006
Sales to DE customers served by DPL		55%		75%
Sales to MD customers served by DPL		68%		77%
Sales to VA customers served by DPL		92%		96%

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Natural Gas Operating Revenue

	2007		2006		Change
Regulated Gas Revenue	$	161.4	$	155.4	$	6.0
Other Gas Revenue		59.8		38.5		21.3
Total Natural Gas Operating Revenue	$	221.2	$	193.9	$	27.3

     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	2007		2006		Change
Residential	$	94.6	$	88.3	$	6.3
Commercial		55.7		55.4		.3
Industrial		6.7		7.9		(1.2)
Transportation and Other		4.4		3.8		.6
Total Regulated Gas Revenue	$	161.4	$	155.4	$	6.0

Regulated Gas Sales (billion cubic feet (Bcf))	2007		2006		Change
Residential		5.6		4.6		1.0
Commercial		3.6		3.1		.5
Industrial		.6		.5		.1
Transportation and Other		4.9		4.5		.4
Total Regulated Gas Sales		14.7		12.7		2.0

Regulated Gas Customers (000s)	2007		2006		Change
Residential		112		111		1
Commercial		9		9		-
Industrial		-		-		-
Transportation and Other		-		-		-
Total Regulated Gas Customers		121		120		1

     Regulated Gas Revenue

     Regulated Gas Revenue increased by $6.0 million primarily due to (i) $8.8 million increase due to colder weather (a 16% increase in Heating Degree Days), (ii) $6.1 million increase due to differences in consumption among the various customer rate classes, (iii) $4.0 million increase

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due to base rate increases effective in November 2006 and April 2007, (iv) $2.2 million increase due to customer growth of 1% in 2007, partially offset by (v) $15.1 million decrease due to Gas Cost Rate decreases effective in November 2006 and April 2007 (offset in Gas Purchased Expense).

Other Gas Revenue increased by $21.3 million to $59.8 million in 2007 from $38.5 million in 2006 primarily due to higher off-system sales (partially offset in Gas Purchased Expense).

Operating Expenses

     Fuel and Purchased Energy

Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply sales, increased by $17.4 million to $656.6 million in 2007, from $639.2 million in 2006. The increase is primarily due to (i) $144.7 million increase in average energy costs, the result of new annual SOS supply contracts, (ii) $14.5 million increase due to higher weather-related sales, partially offset by (iii) $ 120.3 million decrease primarily due to an increase in commercial and industrial customers electing to purchase electricity from competitive suppliers, (iv) $10.8 million decrease in network transmission expenses primarily due to Provider of Last Resort service obligations ending April 1, 2006, and (v) $10.7 million decrease in the Default Electricity Supply deferral balance (partially offset in Default Supply Revenue).

     Gas Purchased

     Total Gas Purchasedincreased by $17.2 million to $171.0 million in 2007, from $153.8 million in 2006. The increase is primarily due to (i) $19.1 million increase in off-system sales, partially offset by (ii) $2.2 million decrease from the settlement of financial hedges (entered into as part of DPL's regulated natural gas hedge program) (partially offset in Regulated Gas Revenue and Other Gas Revenue).

     Other Operation and Maintenance

Other Operation and Maintenance increased by $12.8 million to $151.4 million in 2007, from $138.6 million in 2006. The increase was primarily due to (i) $5.2 million increase in employee related costs, (ii) $3.4 million increase in operations, maintenance and restoration, (iii) $2.8 million increase in Default Electricity Supply costs (primarily deferred and recoverable), (iv) $1.6 million increase in uncollectible reserve expense, and (v) $1.4 million decrease in environmental costs related to a coal gas liability adjustment in 2006.

     Depreciation and Amortization

Depreciation and Amortization decreasedby $1.5 million to $55.9 million in 2007, from $57.4 million in 2006. The decrease is primarily due to fully amortized software.

Other Income (Expense)

Other Expenses(which are net of Other Income) increasedby $2.8 million to $29.8 million in 2007, from $27.0 million in 2006. The increase is primarily due to an increase in interest expense on long term debt.

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Income Tax Expense

     DPL's effective tax rate for the nine months ended September 30, 2007 was 40% as compared to the Federal statutory rate of 35%. The major reasons for the difference between the effective tax rate and the statutory tax rate were state income taxes (net of Federal benefit), a deferred tax adjustment and the flow-through of certain book versus tax depreciation differences, partially offset by changes in estimates related to tax liabilities of prior tax years subject to audit and the flow-through of deferred investment tax credits.

     DPL's effective tax rate for the nine months ended September 30, 2006 was 45% as compared to the Federal statutory rate of 35%. The major reasons for this difference between the effective tax rate and the statutory tax rate were state income taxes (net of Federal benefit), the flow-through of certain book versus tax depreciation differences, and changes in estimates related to tax liabilities of prior tax years subject to audit, partially offset by the flow-through of deferred investment tax credits.

Capital Requirements

Construction Expenditures

     DPL's construction expenditures for the nine months ended September 30, 2007, totaled $92.4 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. For the five year period 2007 through 2011, DPL's currently projected construction expenditures, excluding the costs associated with the PHI Mid-Atlantic Power Pathway Project (the MAPP Project) and the Blueprint for the Future discussed below, are as follows:

	For the Year (in millions)
	2007	2008	2009	2010	2011	Total
Base construction expenditures	$140(a)	$170	$174	$164	$166	$814

     (a)     Includes the $92.4 million expended through September 30, 2007.

     DPL expects to fund these expenditures, and the expenditures associated with the MAPP Project and the Blueprint for the Future, through internally generated cash and from external financing and capital contributions from PHI.

MAPP Project

     On October 17, 2007, Pepco Holdings received the approval of the PJM Board of Managers to build a new 230-mile, 500-kilovolt interstate transmission line as part of PJM's Regional Transmission Expansion Plan to address the reliability objectives of the PJM system. The transmission line, which is referred to as the MAPP Project, will be located in northern Virginia, Maryland, the Delmarva Peninsula and New Jersey. The preliminarily estimated cost of the 500-kilovolt MAPP Project is approximately $1 billion. Construction is expected to occur in sections over a seven-year period with completion targeted by 2014. PHI also plans to add significant 230-kilovolt support lines in Maryland and New Jersey to connect with the new 500-kilovolt line at an approximate cost of $200 million, which brings the total MAPP Project cost to approximately $1.2 billion. PJM continues to evaluate the 230-kilovolt portion of the project

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and a decision is expected in early 2008. The construction costs associated with the MAPP Project and additional 230-kilovolt lines are not included in PHI's current projection of construction expenditures as discussed above. PHI expects to fund the expenditures program through a combination of internally generated funds and external financing.

     DPL's portion of the preliminarily estimated cost of the 500-kilovolt MAPP Project and supporting 230-kilovolt lines Project is approximately $965 million over a projected seven-year construction period beginning in 2008.

Blueprint for the Future

     During 2007, PHI announced an initiative in DPL's service territory referred to as the "Blueprint for the Future." This initiative combines traditional energy efficiency programs with new technologies and systems to help customers manage their energy use and reduce the total cost of energy, including the installation of "smart meters" for all customers in Delaware and Maryland.

     DPL has made filings with the Delaware Public Service Commission and the MPSC for approval of certain aspects of these programs. DPL's preliminarily estimated cost to implement these proposals, if approved by the applicable regulatory commissions, is approximately $209 million over the seven-year period from 2008 to 2014.

FORWARD-LOOKING STATEMENTS

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

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

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

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

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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 market concerns; and

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

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

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

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

ATLANTIC CITY ELECTRIC COMPANY

GENERAL OVERVIEW

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

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

DISCONTINUED OPERATIONS

     On February 8, 2007, ACE completed the sale of the B.L. England generating facility. B.L. England comprised a significant component of ACE's generation operations and its sale requires "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 Statements of Earnings for the three and nine months ended September 30, 2007 and 2006. In September 2006, ACE sold its interests in the Keystone and Conemaugh generating facilities, which for the three and nine months ended September 30, 2006 were reflected as "discontinued operations".

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

	For the three months ended September 30,		For the nine months ended September 30,
	2007	2006	2007	2006
Operating Revenue	$    -	$45.5	$9.7	$100.5
Income Before Income Tax Expense	$    -	$  1.1	$  .2	$    3.8
Net Income	$    -	$    .7	$  .1	$    2.3

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RESULTS OF OPERATIONS

     The accompanying results of operations discussion is for the nine months ended September 30, 2007, compared to the nine months ended September 30, 2006. 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.

Operating Revenue

	2007		2006		Change
Regulated T&D Electric Revenue	$	278.8	$	269.8	$	9.0
Default Supply Revenue		889.8		800.1		89.7
Other Electric Revenue		12.6		10.3		2.3
Total Operating Revenue	$	1,181.2	$	1,080.2	$	101.0

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

     Regulated T&D Electric

Regulated T&D Electric Revenue	2007		2006		Change
Residential	$	137.6	$	134.4	$	3.2
Commercial		84.4		81.8		2.6
Industrial		11.3		11.3		-
Other (Includes PJM)		45.5		42.3		3.2
Total Regulated T&D Electric Revenue	$	278.8	$	269.8	$	9.0

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Regulated T&D Electric Sales (gigawatt hours (GWh))	2007		2006		Change
Residential		3,492		3,395		97
Commercial		3,424		3,341		83
Industrial		861		926		(65)
Other		33		33		-
Total Regulated T&D Electric Sales		7,810		7,695		115

Regulated T&D Electric Customers (000s)	2007		2006		Change
Residential		478		473		5
Commercial		63		63		-
Industrial		1		1		-
Other		1		1		-
Total Regulated T&D Electric Customers		543		538		5

     Regulated T&D Electric Revenue increased by $9.0 million primarily due to the following: (i) $2.6 million increase due to differences in consumption among the various customer rate classes, (ii) $3.2 million increase in network transmission revenues primarily due to an increase in the FERC formula rate in June 2007, (iii) $1.8 million increase due to customer growth of 1.0% in 2007, and (iv) $1.4 million increase due to higher weather-related sales related to a 10% increase in Heating Degree Days.

     Default Electricity Supply

Default Supply Revenue	2007		2006		Change
Residential	$	381.0	$	336.0	$	45.0
Commercial		277.6		257.3		20.3
Industrial		36.8		41.1		(4.3)
Other (Includes PJM)		194.4		165.7		28.7
Total Default Supply Revenue	$	889.8	$	800.1	$	89.7

Default Electricity Supply Sales (GWh)	2007		2006		Change
Residential		3,492		3,395		97
Commercial		2,487		2,422		65
Industrial		276		289		(13)
Other		33		33		-
Total Default Electricity Supply Sales		6,288		6,139		149

Default Electricity Supply Customers (000s)	2007		2006		Change
Residential		478		473		5
Commercial		63		63		-
Industrial		1		1		-
Other		1		1		-
Total Default Electricity Supply Customers		543		538		5

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     Default Supply Revenue increased by $89.7 million primarily due to the following: (i) $49.0 million increase due to higher retail energy rates, primarily the result of new annual market based rates, (ii) $30.4 million increase in wholesale energy revenues due to the sale in PJM Interconnection, LLC (PJM) at higher market prices of electricity purchased from NUGs, (iii) $4.7 million increase due to customer growth of 1.0% in 2007, (iv) $3.3 million increase primarily due to a decrease in commercial and industrial customers electing to purchase electricity from competitive suppliers, and (v) $2.3 million increase due to differences in consumption among the various customer rate classes.

     For the nine months ended September 30, 2007, ACE's customers served energy by ACE represented 81% of ACE's total sales. For the nine months ended September 30, 2006, ACE's customers served energy by ACE represented 80% of ACE's total sales.

Operating Expenses

     Fuel and Purchased Energy and Other Services Costs of Sales

     Fuel and Purchased Energy, associated with Default Electricity Supply sales, increased by $92.9 million to $815.9 million in 2007, from $723.0 in 2006. The increase is primarily due to the following: (i) $80.1 million increase due to new annual BGS supply contracts, (ii) $7.1 million increase due to customer growth, (iii) $4.2 million increase primarily due to differences in consumption among the various customer rate classes, (iv) $3.5 million increase due to higher weather-related sales, partially offset by (v) $2.0 million decrease in network transmission costs (partially offset in Default Supply Revenue).

     Other Operations and Maintenance

     Other Operation and Maintenance increased by $8.7 million to $118.6 million in 2007 from $109.9 million in 2006. The increase was primarily due to the following: (i) $3.6 million increase in employee related costs, (ii) $3.4 million increase in business support costs primarily customer services and accounting, (iii) $1.8 million increase in operations, maintenance and restoration, (iv) $1.3 million increase in Demand Side Management (offset in Deferred Electric Service costs), (v) $0.7 million increase in pole rental expenses, partially offset by (vi) $2.7 million decrease in Default Electricity Supply costs (partially deferred and recoverable).

     Depreciation and Amortization

     Depreciation and Amortization expenses decreased by $38.7 million to $55.5 million in 2007, from $94.2 million in 2006. The decrease is primarily due to lower amortization of regulatory assets resulting from the 2006 sale of ACE's interests in Keystone and Conemaugh.

     Deferred Electric Service Costs

     Deferred Electric Service Costs increased by $37.6 million to an expense of $45.1 million in 2007 from an expense of $7.5 million in 2006. The increase was primarily due to a $37.6 million net over-recovery associated with New Jersey BGS, NUGs, market transition charges and other restructuring items. At September 30, 2007 ACE's balance sheet included as a regulatory liability an over-recovery of $227.1 million with respect to these items, which is net of a $46.0 million reserve for items disallowed by the New Jersey Board of Public Utilities (NJBPU) in a ruling that is under appeal. The $227.1 million regulatory liability also includes

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an $81.3 million gain related to the 2006 sale of ACE's interests in Keystone and Conemaugh, a $24.9 million gain on sale of emission credits related to the B.L. England generating facility, and a $14.7 million loss related to ACE's 2007 sale of B.L. England.

Other Income (Expenses)

     Other Expenses (which are net of other income) decreased by $1.9 million to a net expense of $43.5 million in 2007 from a net expense of $45.4 million in 2006. The decrease is primarily due to a $2.5 million Contribution in Aid of Construction tax gross up in 2006.

Income Tax Expense

     ACE's effective tax rate before discontinued operations for the nine months ended September 30, 2007 was 38% as compared to the Federal statutory rate of 35%. The major reasons for the difference between the effective tax rate and the statutory tax rate were state income taxes (net of Federal benefit), partially offset by changes in estimates related to tax liabilities of prior tax years subject to audit, a deferred tax adjustment and the flow-through of deferred investment tax credits.

     ACE's effective tax rate before excluding discontinued operations for the nine months ended September 30, 2006 was 34% as compared to the Federal statutory rate of 35%. The major reasons for the difference between the effective tax rate and the statutory tax rate were changes in estimates related to tax liabilities of prior tax years subject to audit, an adjustment to accumulated deferred taxes and the flow-through of deferred investment tax credits, partially offset by state income taxes (net of Federal benefit).

Capital Requirements

Construction Expenditures

     ACE's construction expenditures for the nine months ended September 30, 2007, totaled $91 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. For the five year period 2007 through 2011, ACE's currently projected construction expenditures, excluding the costs associated with the PHI Mid-Atlantic Power Pathway Project (the MAPP Project) and the Blueprint for the Future discussed below, are as follows:

	For the Year (in millions)
	2007	2008	2009	2010	2011	Total
Base construction expenditures	$167(a)	$153	$111	$109	$119	$659

     (a)     Includes the $91.0 million expended through September 30, 2007.

     ACE expects to fund these expenditures, and the expenditures associated with the MAPP Project and the Blueprint for the Future, through internally generated cash and from external financing and capital contributions from PHI.

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MAPP Project

     On October 17, 2007, Pepco Holdings received the approval of the PJM Board of Managers to build a new 230-mile, 500-kilovolt interstate transmission line as part of PJM's Regional Transmission Expansion Plan to address the reliability objectives of the PJM system. The transmission line, which is referred to as the MAPP Project, will be located in northern Virginia, Maryland, the Delmarva Peninsula and New Jersey. The preliminarily estimated cost of the 500-kilovolt MAPP Project is approximately $1 billion. Construction is expected to occur in sections over a seven-year period with completion targeted by 2014. PHI also plans to add significant 230-kilovolt support lines in Maryland and New Jersey to connect with the new 500-kilovolt line at an approximate cost of $200 million, which brings the total MAPP Project cost to approximately $1.2 billion. PJM continues to evaluate the 230-kilovolt portion of the project with a decision expected in early 2008. The construction co sts associated with the MAPP Project and additional 230-kilovolt lines are not included in PHI's current projection of construction expenditures as discussed above. PHI expects to fund the expenditures program through a combination of internally generated funds and external financing.

     ACE's portion of the preliminarily estimated cost of the 500-MAPP kilovolt and supporting 230-kilovolt lines Project is approximately $105 million over a projected seven-year construction period beginning in 2008.

Blueprint for the Future

     During 2007, PHI announced an initiative in ACE's service territory referred to as the "Blueprint for the Future." This initiative combines traditional energy efficiency programs with new technologies and systems to help customers manage their energy use and reduce the total cost of energy, including the installation of "smart meters" for all customers in New Jersey.

     ACE intends to file with the NJBPU for approval of certain aspects of these programs. ACE's preliminarily estimated cost to implement these proposals, if approved by the applicable regulatory commissions, is approximately $167 million over the seven-year period from 2008 to 2014.

FORWARD-LOOKING STATEMENTS

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

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

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

· Weather conditions;

· Population growth rates and demographic patterns;

· Competition for retail and wholesale customers;

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

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

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

· Changes in project costs;

· Unanticipated changes in operating expenses and capital expenditures;

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

· Restrictions imposed by Federal and/or state regulatory commissions, PJM, the North American Electric Reliability Council and other applicable electric reliability organizations;

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

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

· Interest rate fluctuations and credit market concerns; and

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

     Any forward-looking statements speak only as to the date of this 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 our business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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

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Item 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

     For information about PHI's derivative activities, other than the information disclosed herein, refer to "Accounting For Derivatives" in Note 2 and "Use of Derivatives in Energy and Interest Rate Hedging Activities" in Note 13 in the Consolidated Financial Statements of PHI, and Item 7A, "Quantitative and Qualitative Disclosures About Market Risk" included in its Annual Report on Form 10-K for the year ended December 31, 2006.

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 retail sales commitments and the cost of supply used to service those commitments in order to ensure stable and known minimum cash flows and fix favorable prices and margins when they become available.

     PHI's risk management policies place oversight at the senior management level through the Corporate Risk Management Committee which has the responsibility for establishing corporate compliance requirements for the Competitive Energy businesses' energy market participation. PHI collectively refers to these energy market activities, including its commodity risk management activities, as "other energy commodity" activities and identifies this activity separately from that of the discontinued proprietary trading activity. PHI uses a value-at-risk (VaR) model to assess the market risk of its Competitive Energy segments' energy commodity activities. PHI also uses other measures to limit and monitor risk in its commodity activities, including limits on the nominal size of positions and periodic loss limits. VaR represents the potential mark-to-market loss on energy contracts or portfolios due to changes in market prices for a specified time period and confidence level. PHI esti mates 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, 2007 (Millions of dollars)
	Proprietary Trading     VaR	VaR for Competitive Energy Activity (1)
95% confidence level, one-day    holding period, one-tailed
Period end	$   -	3.4
Average for the period	$   -	6.1
High	$   -	12.0
Low	$   -	2.1

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

     A significant portion of Conectiv Energy's portfolio of electric generating plants consists of "mid-merit" assets and peaking assets. Mid-merit electric generating plants are typically combined cycle units that can quickly change their megawatt output level on an economic basis. These plants are generally operated during times when demand for electricity rises and power prices are higher. Conectiv Energy economically hedges both the estimated plant output and fuel requirements as the estimated levels of output and fuel needs change. Economic hedge percentages include the estimated electricity output of Conectiv Energy's generation plants and any associated financial or physical commodity contracts (including derivative contracts that are classified as cash flow hedges under SFAS No. 133, other derivative instruments, wholesale normal purchase and sales contracts, and load service obligations).

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

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

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

     As of September 30, 2007, the electricity sold forward by Conectiv Energy as a percentage of projected on-peak plant output combined with on-peak energy purchase commitments was

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113%, 98%, and 24% for the 1-12 month, 13-24 month and 25-36 month forward periods, respectively. Hedge percentages were above the target ranges for the 1-12 month and 13-24 month periods due to Conectiv Energy's success in the default electricity supply auctions and decreases in projected on-peak plant output since the forward sale commitments were entered into. The amount of forward on-peak sales during the 1-12 month period represents 26% of Conectiv Energy's combined total on-peak generating capability and on-peak energy purchase commitments. The volumetric percentages for the forward periods can vary and may not represent the amount of expected value hedged.

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

Credit and Nonperformance Risk

     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, 2007
Rating (1)	Exposure Before Credit Collateral (2)	Credit Collateral (3)	Net Exposure	Number of Counterparties Greater Than 10% (4)	Net Exposure of Counterparties Greater Than 10%
Investment Grade	$70.9	$    -	$70.9
Non-Investment Grade	11.1	1.8	9.3	-
No External Ratings	17.8	.9	16.9	1	$9.8
Credit reserves			1.1

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

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     For additional information concerning market risk, please refer to Item 3, "Quantitative and Qualitative Disclosures About Market Risk -- "Commodity Price Risk" and "Credit and Nonperformance Risk," and for information regarding "Interest Rate Risk," please refer to Item 7A, "Quantitative and Qualitative Disclosures About Market Risk" in Pepco Holdings' Annual Report on Form 10-K for the year ended December 31, 2006.

     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, 2007 and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco Holdings have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to Pepco Holdings and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended (the Exchange Act) (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as a ppropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

     During the three months ended September 30, 2007, 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, 2007, 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

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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, 2007, 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, 2007, 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, 2007, 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, 2007, 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.

188

Changes in Internal Control Over Financial Reporting

     During the three months ended September 30, 2007, 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.

Part II    OTHER INFORMATION

Item 1.   LEGAL PROCEEDINGS

Pepco Holdings

     For information concerning litigation matters, please refer to Note (4), Commitments and Contingencies, to the financial statements of PHI included herein.

Pepco

     For information concerning litigation matters, please refer to Note (4), Commitments and Contingencies, to the financial statements of Pepco included herein.

DPL

     For information concerning litigation matters, please refer to Note (4), Commitments and Contingencies, to the financial statements of DPL included herein.

ACE

     For information concerning litigation matters, please refer to Note (4), Commitments and Contingencies, 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 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Risk Factors" in Pepco Holdings' Annual Report on Form 10-K for the year ended December 31, 2006. There have been no material changes to Pepco Holdings' risk factors as disclosed in the 10-K, except that the following risk factor supersedes the risk factor in the Form 10-K entitled "Pending tax legislation could result in a loss of future tax benefits from cross-border energy sale and leaseback transactions entered into by a PHI subsidiary."

Changes in tax law could have a material adverse effect on the tax benefits that PHI realizes from the portfolio of cross-border energy sale-leaseback transactions entered into by one of its subsidiaries.

     In recent years efforts have been made by members of the U.S. Senate to pass legislation that would have the effect of deferring the deduction of losses associated with leveraged lease transactions involving tax-indifferent parties for taxable years beginning after the year of enactment regardless of when the transaction was entered into. These proposals, which would affect transactions such as those included in PCI's portfolio of cross-border energy leases, would effectively defer the deduction of losses associated with such leveraged lease transactions until the taxable year in which the taxpayer recognized taxable income from the lease, which is typically

189

toward the end of the lease term. To date, no such legislation has been enacted; however, there are continuing efforts by the U.S. Senate to add legislation to various Senate bills directed to the deferral or other curtailment of the tax benefits realized from such transactions. Enactment of legislation of this nature could result in a material delay of the income tax benefits that PHI would receive in connection with PCI's portfolio of cross-border energy leases. Furthermore, under the Financial Accounting Standards Board Staff Position on Financial Accounting Standards 13-2, PHI would be required to adjust the book value of the leases and record a charge to earnings equal to the repricing impact of the deferred deductions which could result in a material adverse effect on PHI's financial condition, results of operations and cash flows.

Pepco

     For a discussion of Pepco's risk factors, please refer to Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Risk Factors" in Pepco's Annual Report on Form 10-K for the year ended December 31, 2006. There have been no material changes to Pepco's risk factors as disclosed in the 10-K.

DPL

     For a discussion of DPL's risk factors, please refer to Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Risk Factors" in DPL's Annual Report on Form 10-K for the year ended December 31, 2006. There have been no material changes to DPL's risk factors as disclosed in the 10-K.

ACE

     For a discussion of ACE's risk factors, please refer to Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Risk Factors" in ACE's Annual Report on Form 10-K for the year ended December 31, 2006. There have been no material changes to ACE's risk factors as disclosed in the 10-K.

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

Pepco Holdings

     None.

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

Item 3.    DEFAULTS UPON SENIOR SECURITIES

Pepco Holdings

     None.

     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.

190

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

Pepco Holdings

     None.

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

Item 5.    OTHER INFORMATION

Pepco Holdings

     None.

Pepco

     None.

DPL

     None.

ACE

     None.

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.

191

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.

192

Exhibit 12.1  Statements Re. Computation of Ratios

PEPCO HOLDINGS

				For the Year Ended December 31,
		Nine Months Ended  September 30, 2007			2006	2005		2004		2003		2002
		(Millions of dollars)
Income before extraordinary item (a)		$	266.2	$	245.0	$	368.5	$	257.4	$	204.9	$	218.7
Income tax expense			140.3		161.4		255.2		167.3		62.1		124.9
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense			260.3		342.8		341.4		376.2		385.9		229.5
Other interest			13.3		18.8		20.3		20.6		21.7		21.0
Preferred dividend requirements     of subsidiaries			.3		1.2		2.5		2.8		13.9		20.6
Total fixed charges			273.9		362.8		364.2		399.6		421.5		271.1
Non-utility capitalized interest			(1.0)		(1.0)		(.5)		(.1)		(10.2)		(9.9)
Income before extraordinary   item, income tax expense,   and fixed charges		$	679.4	$	768.2	$	987.4	$	824.2	$	678.3	$	604.8
Total fixed charges, shown above			273.9		362.8		364.2		399.6		421.5		271.1
Increase preferred stock dividend   requirements of subsidiaries to   a pre-tax amount			.2		.8		1.7		1.8		4.2		11.8
Fixed charges for ratio   computation		$	274.1	$	363.6	$	365.9	$	401.4	$	425.7	$	282.9
Ratio of earnings to fixed charges   and preferred dividends			2.48		2.11		2.70		2.05		1.59		2.14
(a)	Excludes income or losses on equity investments.

193

Exhibit 12.2  Statements Re. Computation of Ratios

PEPCO

				For the Year Ended December 31,
		Nine Months Ended  September 30, 2007			2006	2005		2004		2003		2002
		(Millions of dollars)
Net income (a)		$	111.3	$	85.4	$	165.0	$	96.5	$	103.2	$	141.1
Income tax expense			49.8		57.4		127.6		55.7		67.3		79.1
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense			61.0		77.1		82.8		82.5		83.8		114.5
Other interest			9.0		12.9		13.6		14.3		16.2		17.3
Preferred dividend requirements     of a subsidiary trust			-		-		-		-		4.6		9.2
Total fixed charges			70.0		90.0		96.4		96.8		104.6		141.0
Non-utility capitalized interest			-		-		-		-		-		(.2)
Income before income tax expense,   and fixed charges		$	231.1	$	232.8	$	389.0	$	249.0	$	275.1	$	361.0
Ratio of earnings to fixed charges			3.30		2.59		4.04		2.57		2.63		2.56
Total fixed charges, shown above			70.0		90.0		96.4		96.8		104.6		141.0
Preferred dividend requirements,   excluding mandatorily   redeemable preferred   securities subsequent to   SFAS No. 150 implementation,   adjusted to a pre-tax amount			-		1.7		2.3		1.6		5.5		7.8
Total fixed charges and   preferred dividends		$	70.0	$	91.7	$	98.7	$	98.4	$	110.1	$	148.8
Ratio of earnings to fixed charges   and preferred dividends			3.30		2.54		3.94		2.53		2.50		2.43
(a)	Excludes losses on equity investments.

194

Exhibit 12.3  Statements Re. Computation of Ratios

DPL

			For the Year Ended December 31,
	Nine Months Ended  September 30, 2007			2006	2005		2004		2003		2002
	(Millions of dollars)
Net income	$	35.7	$	42.5	$	74.7	$	63.0	$	52.4	$	51.5
Income tax expense		23.9		32.1		57.6		48.1		37.0		36.9
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense		32.9		41.3		35.3		33.0		37.2		44.1
Other interest		1.7		2.5		2.7		2.2		2.7		3.6
Preferred dividend requirements     of a subsidiary trust		-		-		-		-		2.8		5.7
Total fixed charges		34.6		43.8		38.0		35.2		42.7		53.4
Income before income tax expense,   and fixed charges	$	94.2	$	118.4	$	170.3	$	146.3	$	132.1	$	141.8
Ratio of earnings to fixed charges		2.72		2.70		4.48		4.16		3.09		2.66
Total fixed charges, shown above		34.6		43.8		38.0		35.2		42.7		53.4
Preferred dividend requirements,   adjusted to a pre-tax amount		-		1.4		1.8		1.7		1.7		2.9
Total fixed charges and   preferred dividends	$	34.6	$	45.2	$	39.8	$	36.9	$	44.4	$	56.3
Ratio of earnings to fixed charges   and preferred dividends		2.72		2.62		4.28		3.96		2.98		2.52

195

Exhibit 12.4  Statements Re. Computation of Ratios

ACE

			For the Year Ended December 31,
	Nine Months Ended  September 30, 2007			2006	2005		2004		2003		2002
	(Millions of dollars)
Income from continuing operations	$	53.3	$	60.1	$	51.1	$	58.8	$	31.6	$	17.1
Income tax expense		32.2		33.0		41.2		40.7		20.7		5.9
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense		49.5		64.9		60.1		62.2		63.7		55.6
Other interest		2.5		3.2		3.7		3.4		2.6		2.4
Preferred dividend requirements     of subsidiary trusts		-		-		-		-		1.8		7.6
Total fixed charges		52.0		68.1		63.8		65.6		68.1		65.6
Income before extraordinary   item, income tax expense,   and fixed charges	$	137.5	$	161.2	$	156.1	$	165.1	$	120.4	$	88.6
Ratio of earnings to fixed charges		2.64		2.37		2.45		2.52		1.77		1.35
Total fixed charges, shown above		52.0		68.1		63.8		65.6		68.1		65.6
Preferred dividend requirements   adjusted to a pre-tax amount		.3		.5		.5		.5		.5		.9
Total fixed charges and   preferred dividends	$	52.3	$	68.6	$	64.3	$	66.1	$	68.6	$	66.5
Ratio of earnings to fixed charges   and preferred dividends		2.63		2.35		2.43		2.50		1.76		1.33

196

Exhibit 31.1
CERTIFICATION
I, Dennis R. Wraase, certify that:
1.	I have reviewed this report on Form 10-Q of Pepco Holdings, Inc.
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b)	Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
	c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:
	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:  November 1, 2007			/s/ D. R. WRAASE                          Dennis R. Wraase Chairman of the Board, President   and Chief Executive Officer

197

Exhibit 31.2
CERTIFICATION
I, Paul H. Barry, certify that:
1.		I have reviewed this report on Form 10-Q of Pepco Holdings, Inc.
2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.		The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b)		Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
	c)		Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d)		Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:
	a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:  November 1, 2007				/s/ P. H. BARRY                     Paul H. Barry Senior Vice President and   Chief Financial Officer

198

Exhibit 31.3
CERTIFICATION
I, Joseph M. Rigby, certify that:
1.		I have reviewed this report on Form 10-Q of Potomac Electric Power Company.
2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.		The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
	a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b)		Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	c)		Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:
	a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:  November 1, 2007				/s/ J. M. RIGBY                                      Joseph M. Rigby President and Chief Executive Officer

199

Exhibit 31.4
CERTIFICATION
I, Paul H. Barry, certify that:
1.	I have reviewed this report on Form 10-Q of Potomac Electric Power Company.
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
		a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		b)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		c)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.		The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:  November 1, 2007				/s/ P. H. BARRY                     Paul H. Barry Senior Vice President and   Chief Financial Officer

200

Exhibit 31.5
CERTIFICATION
I, Joseph M. Rigby, certify that:
1.	I have reviewed this report on Form 10-Q of Delmarva Power & Light Company.
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
		a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		b)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		c)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.		The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:  November 1, 2007				/s/ J. M. RIGBY                                      Joseph M. Rigby President and Chief Executive Officer

201

Exhibit 31.6
CERTIFICATION
I, Paul H. Barry, certify that:
1.	I have reviewed this report on Form 10-Q of Delmarva Power & Light Company.
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
		a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		b)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		c)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.		The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:  November 1, 2007				/s/ P. H. BARRY                     Paul H. Barry Senior Vice President and   Chief Financial Officer

202

Exhibit 31.7
CERTIFICATION
I, Joseph M. Rigby, certify that:
1.	I have reviewed this report on Form 10-Q of Atlantic City Electric Company.
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
		a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		b)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		c)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.		The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:  November 1, 2007				/s/ J. M. RIGBY                                      Joseph M. Rigby President and Chief Executive Officer

203

Exhibit 31.8
CERTIFICATION
I, Paul H. Barry, certify that:
1.	I have reviewed this report on Form 10-Q of Atlantic City Electric Company.
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
		a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		b)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		c)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.		The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors:
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:  November 1, 2007				/s/ P. H. BARRY                     Paul H. Barry Chief Financial Officer

204

Exhibit 32.1
Certificate of Chief Executive Officer and Chief Financial Officer of Pepco Holdings, Inc. (pursuant to 18 U.S.C. Section 1350)
I, Dennis R. Wraase, and I, Paul H. Barry, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Pepco Holdings, Inc. for the quarter ended September 30, 2007, 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.
November 1, 2007	/s/ D. R. WRAASE                     Dennis R. Wraase Chairman of the Board, President   and Chief Executive Officer
November 1, 2007	/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.

205

Exhibit 32.2
Certificate of Chief Executive Officer and Chief Financial Officer of Potomac Electric Power Company (pursuant to 18 U.S.C. Section 1350)
I, Joseph M. Rigby, and I, Paul H. Barry, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Potomac Electric Power Company for the quarter ended September 30, 2007, 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.
November 1, 2007	/s/ J. M. RIGBY                                      Joseph M. Rigby President and Chief Executive Officer
November 1, 2007	/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.

206

Exhibit 32.3
Certificate of Chief Executive Officer and Chief Financial Officer of Delmarva Power & Light Company (pursuant to 18 U.S.C. Section 1350)
I, Joseph M. Rigby, and I, Paul H. Barry, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Delmarva Power & Light Company for the quarter ended September 30, 2007, 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.
November 1, 2007	/s/ J. M. RIGBY                                      Joseph M. Rigby President and Chief Executive Officer
November 1, 2007	/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.

207

Exhibit 32.4
Certificate of Chief Executive Officer and Chief Financial Officer of Atlantic City Electric Company (pursuant to 18 U.S.C. Section 1350)
I, Joseph M. Rigby, and I, Paul H. Barry, certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Atlantic City Electric Company for the quarter ended September 30, 2007, 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.
November 1, 2007	/s/ J. M. RIGBY                                      Joseph M. Rigby President and Chief Executive Officer
November 1, 2007	/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.

208

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.

      November 1, 2007 PEPCO HOLDINGS, INC. (PHI)
POTOMAC ELECTRIC POWER COMPANY (Pepco)
DELMARVA POWER & LIGHT COMPANY (DPL)
ATLANTIC CITY ELECTRIC COMPANY (ACE)
       (Registrants) By    /s/ P. H. BARRY                    
        Paul H. Barry
        Senior Vice President and
        Chief Financial Officer,
            PHI, Pepco and DPL
        Chief Financial Officer, ACE

209

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

210