Pepco 10-Q 2008 Q2 Quarterly report

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 June 30, 2008

Commission File Number	Name of Registrant, State of Incorporation, Address of Principal Executive Offices, and Telephone Number	I.R.S. Employer Identification Number
001-31403	PEPCO HOLDINGS, INC.   (Pepco Holdings or PHI), a Delaware corporation 701 Ninth Street, N.W. Washington, D.C.  20068 Telephone: (202)872-2000	52-2297449
001-01072	POTOMAC ELECTRIC POWER COMPANY   (Pepco), a District of Columbia and     Virginia corporation 701 Ninth Street, N.W. Washington, D.C.  20068 Telephone: (202)872-2000	53-0127880
001-01405	DELMARVA POWER & LIGHT COMPANY   (DPL), a Delaware and Virginia corporation 800 King Street, P.O. Box 231 Wilmington, Delaware  19899 Telephone: (202)872-2000	51-0084283
001-03559	ATLANTIC CITY ELECTRIC COMPANY   (ACE), a New Jersey corporation 800 King Street, P.O. Box 231 Wilmington, Delaware  19899 Telephone: (202)872-2000	21-0398280

Continued

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

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

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

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

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

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

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

Registrant	Number of Shares of Common Stock of the Registrant Outstanding at June 30, 2008
Pepco Holdings	201,759,071   ($.01 par value)
Pepco	100   ($.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	112
Item 3.	-	Quantitative and Qualitative Disclosures    About Market Risk	180
Item 4.	-	Controls and Procedures	183
Item 4T.	-	Controls and Procedures	183
PART II	OTHER INFORMATION		185
Item 1.	-	Legal Proceedings	185
Item 1A.	-	Risk Factors	185
Item 2.	-	Unregistered Sales of Equity Securities and Use of Proceeds	187
Item 3.	-	Defaults Upon Senior Securities	187
Item 4.	-	Submission of Matters to a Vote of Security Holders	187
Item 5.	-	Other Information	188
Item 6.	-	Exhibits	189
Signatures			206

TABLE OF CONTENTS – EXHIBITS
Exh. No.	Registrant(s)	Description of Exhibit	Page
12.1	PHI	Statements Re: Computation of Ratios	190
12.2	Pepco	Statements Re: Computation of Ratios	191
12.3	DPL	Statements Re: Computation of Ratios	192
12.4	ACE	Statements Re: Computation of Ratios	193
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	194
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	195
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	196
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	197
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	198
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	199
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	200
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	201
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	202
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	203
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	204
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	205

GLOSSARY OF TERMS

Term	Definition
2007 Maryland Rate Orders	The MPSC orders approving new electric service distribution base rates for Pepco and DPL in Maryland, each effective June 16, 2007
A&N	A&N Electric Cooperative, purchaser of DPL’s retail electric distribution business in Virginia
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
ADITC	Accumulated deferred investment tax credits
Ancillary services	Generally, electricity generation reserves and reliability services
AOCI	Accumulated Other Comprehensive Income
APIC	Additional paid-in capital
Appeals Office	U.S. Office of Appeals of the IRS
ARB	Accounting Research Bulletin
BGS	Basic Generation Service (the supply of electricity by ACE to retail customers in New Jersey who have not elected to purchase electricity from a competitive supplier)
BSA	Bill Stabilization Adjustment mechanism
Citgo	Citgo Asphalt Refining Company
Conectiv	A wholly owned subsidiary of PHI which is a holding company under PUHCA 2005 and the parent of DPL and ACE
Conectiv Energy	Conectiv Energy Holding Company and its subsidiaries
Conectiv Group	Conectiv and certain of its subsidiaries that were involved in a like-kind exchange transaction under examination by the IRS
Cooling Degree Days	Daily difference in degrees by which the mean (high and low divided by 2) dry bulb temperature is above a base of 65 degrees Fahrenheit
DCPSC	District of Columbia Public Service Commission
Default Electricity   Supply	The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as SOS or BGS service
Default Supply Revenue	Revenue received for Default Electricity Supply
Delaware District Court	United States District Court for the District of Delaware
DPL	Delmarva Power & Light Company
DRP	PHI’s Shareholder Dividend Reinvestment Plan
EDIT	Excess Deferred Income Taxes
EITF	Emerging Issues Task Force
EPA	U.S. Environmental Protection Agency
EPS	Earnings per share
ERISA	Employment Retirement Income Security Act of 1974
Exchange Act	Securities Exchange Act of 1934, as amended
FAS	Financial Accounting Standards
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation Number
FSP	FASB Staff Position

i 

Term	Definition
GAAP	Accounting principles generally accepted in the United States of America
GAAP hierarchy	The sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP
GWh	Gigawatt hour
Heating Degree Days	Daily difference in degrees by which the mean (high and low divided by 2) dry bulb temperature is below a base of 65 degrees Fahrenheit.
IRC	Internal Revenue Code
IRS	Internal Revenue Service
ISONE	Independent System Operator - New England
LILO	Lease-in/lease-out
LTIP	Pepco Holdings’ Long-Term Incentive Plan
MAPP Project	Mid-Atlantic Power Pathway Project
Mirant	Mirant Corporation
MPSC	Maryland Public Service Commission
NFA	No Further Action letter issued by the NJDEP
NGC	Non Utility Generation Charge in New Jersey
NJBPU	New Jersey Board of Public Utilities
NJDEP	New Jersey Department of Environmental Protection
Normalization   provisions	Sections of the IRC and related regulations that dictate how excess deferred income taxes resulting from the corporate income tax rate reduction enacted by the Tax Reform Act of 1986 and accumulated deferred investment tax credits should be treated for ratemaking purposes
NUGs	Non-utility generators
NYDEC	New York Department of Environmental Conservation
OCI	Other Comprehensive Income
ODEC	Old Dominion Electric Cooperative, purchaser of DPL’s wholesale transmission business in Virginia
Panda	Panda-Brandywine, L.P.
Panda PPA	PPA between Pepco and Panda
PBO	Projected benefit obligation
PCI	Potomac Capital Investment Corporation and its subsidiaries
Pepco	Potomac Electric Power Company
Pepco Energy Services	Pepco Energy Services, Inc. and its subsidiaries
Pepco Holdings or PHI	Pepco Holdings, Inc.
PHI Parties	The PHI Retirement Plan, PHI and Conectiv, parties to cash balance plan litigation brought by three management employees of PHI Service Company
PHI Retirement Plan	PHI’s noncontributory retirement plan
PJM	PJM Interconnection, LLC
PJM RTO	PJM Regional Transmission Organization
Power Delivery	PHI’s Power Delivery Business
PPA	Power Purchase Agreement
PRP	Potentially responsible party

ii 

Term	Definition
PUHCA 2005	Public Utility Holding Company Act of 2005
RAR	IRS revenue agent’s report
RC Cape May	RC Cape May Holdings, LLC, an affiliate of Rockland Capital Energy Investments, LLC, and the purchaser of the B.L. England generating facility
Regulated T&D Electric   Revenue	Revenue from the transmission and the delivery of electricity to PHI’s customers within its service territories at regulated rates
Revenue Decoupling   Adjustment	Amount by which revenue from Maryland distribution sales either exceeds or falls short of the MPSC-approved revenue based on the distribution charge per customer in the 2007 Maryland Rate Orders
ROE	Return on equity
RPM	Reliability Pricing Model
SBC	Societal Benefits Charge in New Jersey
SBPA	Standby Bond Purchase Agreement
SEC	Securities and Exchange Commission
Sempra	Sempra Energy Trading LLC
SFAS	Statement of Financial Accounting Standards
SILO	Sale-in/lease-out
SOS	Standard Offer Service (the supply of electricity by Pepco in the District of Columbia, by Pepco and DPL in Maryland and by DPL in Delaware, to retail customers who have not elected to purchase electricity from a competitive supplier)
Spot	Commodities market in which goods are sold for cash and delivered immediately
Standard Offer Service   revenue or SOS revenue	Revenue Pepco and DPL, respectively, receive for the procurement of energy for its SOS customers
Starpower	Starpower Communications, LLC
Stranded costs	Costs incurred by a utility in connection with providing service which would be unrecoverable in a competitive or restructured market.  Such costs may include costs for generation assets, purchased power costs, and regulatory assets and liabilities, such as accumulated deferred income taxes.
Transfer Agreement	An agreement with Panda and Sempra under which Pepco has agreed, in exchange for a payment from Pepco to Sempra, to transfer the Panda PPA to Sempra
Transition Bonds	Transition bonds issued by ACE Funding
Treasury lock	A hedging transaction that allows a company to “lock-in” a specific interest rate corresponding to the rate of a designated Treasury bond for a determined period of time
TSA	Contract for terminal services between ACE and Citgo
VaR	Value at Risk
VRDB	Variable Rate Demand Bonds

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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	72	92
Consolidated Statements of Comprehensive Earnings	4	N/A	N/A	N/A
Consolidated Balance Sheets	5	50	73	93
Consolidated Statements of Cash Flows	7	52	75	95
Notes to Consolidated Financial Statements	8	53	76	96

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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EARNINGS (Unaudited)
	Three Months Ended June 30,				Six Months Ended June 30,
		2008		2007		2008		2007
	(In millions, except per share data)
Operating Revenue
Power Delivery	$	1,296.2	$	1,162.3	$	2,591.7	$	2,437.4
Competitive Energy		1,328.9		904.1		2,657.1		1,791.2
Other		(106.9)		17.9		(89.7)		34.5
Total Operating Revenue		2,518.2		2,084.3		5,159.1		4,263.1
Operating Expenses
Fuel and purchased energy		1,832.6		1,412.4		3,650.1		2,889.4
Other services cost of sales		179.6		134.6		359.9		272.7
Other operation and maintenance		230.1		210.8		449.6		417.9
Depreciation and amortization		92.7		92.7		183.6		185.8
Other taxes		85.4		86.2		173.6		171.5
Deferred electric service costs		(16.7)		(10.0)		8.0		18.1
Impairment loss		-		1.6		-		1.6
Gain on sale of assets		-		-		(3.1)		(2.5)
Total Operating Expenses		2,403.7		1,928.3		4,821.7		3,954.5
Operating Income		114.5		156.0		337.4		308.6
Other Income (Expenses)
Interest and dividend income		5.1		3.5		12.2		6.8
Interest expense		(80.1)		(83.8)		(161.1)		(168.4)
Income (loss) from equity investments		.1		3.7		(2.0)		7.1
Other income		4.2		6.8		9.8		15.4
Other expenses		(.6)		(.2)		(1.2)		(.4)
Total Other Expenses		(71.3)		(70.0)		(142.3)		(139.5)
Preferred Stock Dividend Requirements of Subsidiaries		-		.1		.1		.2
Income Before Income Tax Expense		43.2		85.9		195.0		168.9
Income Tax Expense		28.2		28.7		80.8		60.1
Net Income		15.0		57.2		114.2		108.8
Retained Earnings at Beginning of Period		1,237.6		1,062.6		1,192.7		1,068.7
Cumulative Effect Adjustment Related to the    Implementation of FIN 48		-		-		-		(7.4)
LTIP Dividend		(.1)		-		(.2)		(.2)
Dividends Paid on Common Stock (Note 13)		(54.3)		(50.2)		(108.5)		(100.3)
Retained Earnings at End of Period	$	1,198.2	$	1,069.6	$	1,198.2	$	1,069.6
Basic and Diluted Share Information
Weighted average shares outstanding		201.4		193.2		201.2		192.8
Earnings per share of common stock	$	.07	$	.30	$	.57	$	.56

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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS (Unaudited)
	Three Months Ended June 30,				Six Months Ended June 30,
		2008		2007		2008		2007
		(Millions of dollars)
Net income	$	15.0	$	57.2	$	114.2	$	108.8
Other comprehensive earnings
Unrealized gains (losses) on commodity     derivatives designated as cash flow hedges:
Unrealized holding gains arising during period		419.8		1.6		628.4		20.3
Less:  reclassification adjustment for                 gains (losses) included in net earnings		59.7		(.7)		71.5		(12.5)
Net unrealized gains on commodity derivatives		360.1		2.3		556.9		32.8
Realized gains on Treasury lock transactions		1.3		3.3		2.7		6.2
Amortization of gains and losses for prior service costs		(5.3)		-		(5.0)		-
Other comprehensive earnings, before taxes		356.1		5.6		554.6		39.0
Income tax expense		147.6		3.2		226.5		15.0
Other comprehensive earnings, net of income taxes		208.5		2.4		328.1		24.0
Comprehensive earnings	$	223.5	$	59.6	$	442.3	$	132.8

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

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PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
ASSETS		June 30, 2008		December 31, 2007
	(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$	291.4	$	55.1
Restricted cash			62.7		14.5
Accounts receivable, less allowance for uncollectible      accounts of $33.1 million and $30.6 million, respectively			1,518.2		1,278.3
Fuel, materials and supplies-at average cost			345.4		287.9
Unrealized gains - derivative contracts			367.6		43.0
Prepayments of income taxes			266.2		249.8
Prepaid expenses and other			142.2		68.5
Total Current Assets			2,993.7		1,997.1
INVESTMENTS AND OTHER ASSETS
Goodwill			1,409.0		1,409.6
Regulatory assets			1,594.0		1,515.7
Investment in finance leases held in trust			1,307.3		1,384.4
Income taxes receivable			199.9		196.1
Restricted cash and cash equivalents			416.9		424.1
Other			390.2		307.3
Total Investments and Other Assets			5,317.3		5,237.2
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			12,556.9		12,306.5
Accumulated depreciation			(4,502.3)		(4,429.8)
Net Property, Plant and Equipment			8,054.6		7,876.7
TOTAL ASSETS		$	16,365.6	$	15,111.0

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

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PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY	June 30, 2008		December 31, 2007
	(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt	$	308.7	$	288.8
Current maturities of long-term debt and project funding		250.8		332.2
Accounts payable and accrued liabilities		1,047.1		796.7
Capital lease obligations due within one year		6.2		6.0
Taxes accrued		167.0		133.5
Interest accrued		68.7		70.1
Liabilities and accrued interest related to uncertain tax positions		80.0		131.7
Other		475.6		277.8
Total Current Liabilities		2,404.1		2,036.8
DEFERRED CREDITS
Regulatory liabilities		1,272.1		1,248.9
Deferred income taxes, net		2,325.6		2,105.1
Investment tax credits		36.7		38.9
Pension benefit obligation		150.9		65.5
Other postretirement benefit obligations		428.9		385.5
Income taxes payable		170.4		164.9
Liabilities and accrued interest related to uncertain tax positions		157.3		65.1
Other		237.4		241.1
Total Deferred Credits		4,779.3		4,315.0
LONG-TERM LIABILITIES
Long-term debt		4,260.0		4,174.8
Transition Bonds issued by ACE Funding		418.3		433.5
Long-term project funding		19.8		20.9
Capital lease obligations		102.3		105.4
Total Long-Term Liabilities		4,800.4		4,734.6
COMMITMENTS AND CONTINGENCIES (NOTE 13)
MINORITY INTEREST		6.2		6.2
SHAREHOLDERS’ EQUITY
Common stock, $.01 par value, authorized 400,000,000 shares,     201,759,071 shares and 200,512,890 shares outstanding, respectively		2.0		2.0
Premium on stock and other capital contributions		2,892.8		2,869.2
Accumulated other comprehensive earnings (loss)		282.6		(45.5)
Retained earnings		1,198.2		1,192.7
Total Shareholders’ Equity		4,375.6		4,018.4
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	16,365.6	$	15,111.0

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

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PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
	Six Months Ended June 30,
		2008		2007
	(Millions of dollars)
OPERATING ACTIVITIES
Net income	$	114.2	$	108.8
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		183.6		185.8
Gain on sale of assets		(3.1)		(2.5)
Loss (gain) on sale of other investment		.7		(.7)
Impairment loss		-		1.6
Rents received from cross-border energy leases under income earned		(37.3)		(38.1)
Non-cash charge to reduce equity value of PHI’s cross-border energy lease investments		124.4		-
Deferred income taxes		1.2		58.0
Pension and other postretirement benefit obligations		15.7		16.1
Net unrealized (gains) losses on commodity derivatives accounted for at fair value		(22.6)		8.3
Changes in:
Accounts receivable		(201.3)		(60.6)
Regulatory assets and liabilities		(8.8)		(24.2)
Materials and supplies		(57.8)		(8.6)
Accounts payable and accrued liabilities		228.7		89.8
Interest and taxes accrued		4.1		(21.6)
Cash collateral related to derivative activities		394.5		28.2
Other changes in working capital		(46.7)		(37.6)
Net other operating		3.8		12.1
Net Cash From Operating Activities		693.3		314.8
INVESTING ACTIVITIES
Net investment in property, plant and equipment		(365.8)		(285.0)
Proceeds from sale of assets		51.2		10.6
Changes in restricted cash		(48.2)		(.9)
Net other investing activities		2.2		2.7
Net Cash Used By Investing Activities		(360.6)		(272.6)
FINANCING ACTIVITIES
Dividends paid on common stock		(108.5)		(100.3)
Dividends paid on preferred stock		(.1)		(.2)
Common stock issued for the Dividend Reinvestment Plan		14.3		14.1
Issuance of common stock		14.6		23.9
Redemption of preferred stock of subsidiaries		-		(18.2)
Issuances of long-term debt		400.0		451.4
Reacquisition of long-term debt		(405.2)		(364.2)
Issuances (repayments) of short-term debt, net		19.9		(63.6)
Cost of issuances		(11.4)		(2.5)
Net other financing activities		(20.0)		(8.4)
Net Cash Used By Financing Activities		(96.4)		(68.0)
Net Increase (Decrease) in Cash and Cash Equivalents		236.3		(25.8)
Cash and Cash Equivalents at Beginning of Period		55.1		48.8
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	291.4	$	23.0
NONCASH ACTIVITIES
Asset retirement obligations associated with removal   costs transferred to regulatory liabilities	$	1.9	$	7.3
Recoverable pension/OPEB costs included in regulatory assets	$	94.6	$	-
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid (received) for income taxes	$	75.5	$	(6.3)

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PEPCO HOLDINGS, INC.

(1)  ORGANIZATION

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

· electricity and natural gas delivery (Power Delivery), conducted through the following regulated public utility companies, each of which is a reporting company under the Securities Exchange Act of 1934, as amended:

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

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

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

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

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

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

Power Delivery

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

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

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PEPCO HOLDINGS

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

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

Delaware Standard Offer Service (SOS)

District of Columbia SOS

Maryland SOS

New Jersey Basic Generation Service (BGS)

Virginia Default Service (prior to January 2, 2008)

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

Competitive Energy

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

Other Business Operations

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy lease investments, with a book value at June 30, 2008 of approximately $1.3 billion.  This activity constitutes a fourth operating segment, which is designated as “Other Non-Regulated” for financial reporting purposes.  For a discussion of  PHI’s cross-border energy lease investments, see , “Change in Accounting Estimate,” in Note (2), “Leasing Activities” in Note (5), “Income Taxes” in Note (9) and “Commitments and Contingencies — Regulatory and Other Matters — PHI’s Cross-Border Energy Lease Investments,” in Note (13).

(2)  SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

Pepco Holdings’ unaudited consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP).  Pursuant to the rules and regulations of the Securities and Exchange Commission (SEC), certain information and footnote disclosures normally included in annual financial statements prepared

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in accordance with GAAP have been omitted.  Therefore, these financial statements should be read along with the annual financial statements included in PHI’s Annual Report on Form 10-K for the year ended December 31, 2007.  In the opinion of PHI’s management, the consolidated financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly Pepco Holdings’ financial condition as of June 30, 2008, in accordance with GAAP.  The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.  Interim results for the three and six months ended June 30, 2008 may not be indicative of PHI’s results that will be realized for the full year ending December 31, 2008, since its Power Delivery and Competitive Energy businesses are seasonal.

Change in Accounting Estimate

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

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

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

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investments.  Based on this reassessment, PHI for the quarter ended June 30, 2008, has recorded an after-tax charge to net income of $92.9 million, consisting of the following components:

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

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

The charge pursuant to FSP 13-2 reflects changes to the book equity value of the cross-border energy lease investments and the pattern of recognizing the related cross-border energy lease income.  This amount will be recognized as income over the remaining term of the affected leases, which expire between 2017 and 2047.  The tax benefits associated with the lease transactions represent timing differences that do not change the aggregate amount of lease net income over the life of the transactions.

FIN 46R, “Consolidation of Variable Interest Entities”

Subsidiaries of Pepco Holdings have power purchase agreements (PPAs) with a number of entities.  These PPAs consist of:

·   Three contracts between unaffiliated non-utility generators (NUGs) and ACE, and

·   An agreement of Pepco with Panda-Brandywine, L.P. (Panda) entered into in 1991, pursuant to which Pepco is obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (Panda PPA).

Due to a variable element in the pricing structure of the NUGs and the Panda PPA, the Pepco Holdings’ subsidiaries potentially assume the variability in the operations of the plants related to these PPAs and therefore have a variable interest in the counterparties to these PPAs.  In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R (revised December 2003), entitled “Consolidation of Variable Interest Entities” (FIN 46R) and FASB Staff Position (FSP) 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)” (FSP FIN 46(R)-6), Pepco Holdings continued, during the second quarter of 2008, to conduct exhaustive efforts to obtain information from these four entities, but was unable to obtain sufficient information to conduct the analysis required under FIN 46R to determine whether these four entities were variable interest entities or if Pepco Holdings’ subsidiaries were the primary beneficiaries.  As a result, Pepco Holdings has applied the scope exemption from the application of FIN 46R for enterprises that have conducted exhaustive efforts to obtain the necessary information, but have not been able to obtain such information.

Net purchase activities with the counterparties to the NUGs and the Panda PPA for the three months ended June 30, 2008 and 2007 were approximately $105 million and $97 million, respectively, of which approximately $96 million and $90 million, respectively, were related to

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power purchases under the NUGs and the Panda PPA.  Net purchase activities with the counterparties to the NUGs and the Panda PPA for the six months ended June 30, 2008 and 2007 were approximately $213 million and $203 million, respectively, of which approximately $193 million and $186 million, respectively, were related to power purchases under the NUGs and the Panda PPA.  Pepco Holdings does not have loss exposure under the NUGs because cost recovery will be achieved from ACE’s customers through regulated rates.  There is no loss exposure under the Panda PPA because recovery will be achieved through the sale of purchased power into PJM Interconnection, LLC (PJM), with the funds received from the Mirant Corporation (Mirant) bankruptcy settlement covering the amount by which the purchase cost exceeds the proceeds from the sale.  On June 20, 2008, Pepco entered into an agreement to sell the Panda PPA to Sempra Energy Trading LLP in a transaction that is expected to close later this year.  See Note (13) “Commitments and Contingencies — Regulatory and Other Matters — Proceeds from Settlement of Mirant Bankruptcy Claims.”

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $73.9 million and $76.9 million for the three months ended June 30, 2008 and 2007, respectively and $148.1 million and $150.1 million for the six months ended June 30, 2008 and 2007, respectively.

Goodwill

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

Balance, December 31, 2007	$	1,409.6
Less:  Changes in estimates during the second quarter of 2008                 related to pre-merger tax contingencies		(0.6)
Balance, June 30, 2008	$	1,409.0

Reclassifications

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

(3)  NEWLY ADOPTED ACCOUNTING STANDARDS

SFAS No. 157, "Fair Value Measurements"

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

SFAS No. 157 nullified a portion of Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,”(EITF 02-3). Under EITF 02-3, the transaction price presumption prohibited recognition of a trading profit at

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inception of a derivative unless the positive fair value of that derivative was substantially based on quoted prices or a valuation process incorporating observable inputs.  For transactions that did not meet this criterion at inception, trading profits that had been deferred were recognized in the period that inputs to value the derivative became observable or when the contract was performed.  SFAS No. 157 nullified this portion of EITF 02-3.  SFAS No. 157 also: (1) establishes that fair value is based on a hierarchy of inputs into the valuation process (as described in Note 12), (2) clarifies that an issuer's credit standing should be considered when measuring liabilities at fair value, (3) precludes the use of a liquidity or blockage factor discount when measuring instruments traded in an actively quoted market at fair value and (4) requires costs relating to acquiring instruments carried at fair value to be recognized as expense when incurred.  SFAS No. 157 requires that a fair value measurement reflect the assumptions market participants would use in pricing an asset or liability based on the best available information.  These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model.

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

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

Pepco Holdings applied the guidance of FSP No. 157-1 and FSP No. 157-2 with its adoption of SFAS No. 157 on January 1, 2008.  The adoption of SFAS No. 157 did not result in a transition adjustment to beginning retained earnings and did not have a material impact on PHI’s overall financial condition, results of operations or cash flows.  SFAS No. 157 also requires new disclosures regarding the level of pricing observability associated with financial instruments carried at fair value.  This additional disclosure is provided in Note 12, “Fair Value Disclosures,” herein.  Additionally, with the deferral of the effective date of SFAS No. 157 for certain non-financial assets and non-financial liabilities under FSP No. 157-2, PHI does not anticipate any material changes to its overall financial condition, results of operations or cash flows.

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

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

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

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

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

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

Pepco Holdings retrospectively adopted the provisions of FSP FIN 39-1 and elected to offset fair value amounts recognized for derivative instruments and fair value amounts recognized for related collateral positions executed with the same counterparty under a master netting arrangement.  Additional disclosure of collateral positions that have been offset against net derivative positions is provided in Note 14.  The effect of retrospective application of FSP FIN 39-1 was not material at December 31, 2007 and, as such, no amounts were reclassified.

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

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

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

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

(4)  RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

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

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

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

This Statement amends FASB Statement No. 109, “Accounting for Income Taxes”to require the acquirer to recognize changes in the amount of its deferred tax benefits that are recognizable because of a business combination either in income from continuing operations in

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the period of the combination or directly in contributed capital, depending on the circumstances (such changes arise through the increase or reduction of the acquirer’s valuation allowance on its previously existing deferred tax assets because of the business combination).  Previously, Statement 109 required a reduction of the acquirer’s valuation allowance because of a business combination to be recognized through a corresponding reduction to goodwill.

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

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

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

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

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

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

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

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

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

FSP FAS 142-3, “Determination of the Useful Life of Intangible Assets”

On April 25, 2008, the FASB issued FSP Financial Accounting Standards (FAS) 142-3, “Determination of the Useful Life of Intangible Assets,” (FSP FAS 142-3) which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142).  The intent of FSP FAS 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combinations,” and other U.S. generally accepted accounting principles (GAAP).

In developing assumptions about renewal or extension used to determine the useful life of a recognized intangible asset, an entity should consider its own historical experience in renewing or extending similar arrangements; however, these assumptions should be adjusted for entity-specific factors as discussed in SFAS No. 142.  In the absence of that experience, an entity should consider the assumptions that market participants would use about renewal or extension (consistent with the highest and best use of the asset by market participants), adjusted for the entity-specific factors as discussed in SFAS No. 142.

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FSP FAS 142-3 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for Pepco Holdings).  Early adoption is prohibited.  The guidance for determining the useful life of a recognized intangible asset in FSP FAS 142-3 shall be applied prospectively to intangible assets acquired after the effective date.  The disclosure requirements shall be applied prospectively to all intangible assets recognizedas of, and subsequent to, the effective date. Pepco Holdings is currently evaluating the impact FSP FAS 142-3 may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

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

On May 9, 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162) which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP in the United States (the GAAP hierarchy).  Moving the GAAP hierarchy into the accounting literature appropriately directs the hierarchy to the reporting entity responsible for the content of the financial statements, rather than to the auditors.

SFAS No. 162 is effective sixty days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of ‘Present fairly in conformity with generally accepted accounting principles’.”  The application of SFAS No. 162 is not expected to result in a change in accounting; however, if it does, the accounting change must be reported as a change in accounting principle under SFAS No. 154, “Accounting Changes and Error Corrections.”  Pepco Holdings is currently evaluating the impact SFAS No. 162 may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

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

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

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

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FSP APB 14-1 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for Pepco Holdings).  FSP APB 14-1 shall be applied retrospectively to all periods presented.  Early adoption is not permitted.  Pepco Holdings does not currently have any convertible debt instruments outstanding; however, these types of instruments may be considered for financing future endeavors.

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

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

In accordance with FSP EITF 03-6-1, unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method.  The holder of a share-based payment award that includes nonforfeitable rights to dividends or dividend equivalents receives a noncontingent transfer of value each time an entity declares a dividend or dividend equivalent during the contractual period of the share-based payment award.  As a result, the award meets the definition of a participating security prior to the requisite service having been rendered for the award.

EITF 03-6-1 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for Pepco Holdings).  All prior period EPS data presented shall be adjusted retrospectively (including interim financial statements, summaries of earnings, and selected financial data) to conform with the provisions of EITF 03-6-1.  Early application is not permitted.  Pepco Holdings is currently evaluating the impact EITF 03-6-1 may have on its earnings per share calculations.

(5)  LEASING ACTIVITIES

Investment in Finance Leases Held in Trust

As of June 30, 2008 and December 31, 2007, Pepco Holdings had cross-border energy lease investments of $1,307.3 million and $1,384.4 million, respectively, consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks located outside of the United States.

As further discussed in Note (2) and Note (13), PHI has reassessed the sustainability of its tax position and has revised its assumptions regarding the estimated timing of tax benefits generated from its cross-border energy lease investments.  Based on this reassessment, PHI for the quarter ended June 30, 2008, has recorded a reduction in its cross-border energy lease investments of $124.4 million.

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

	June 30, 2008		December 31, 2007
	(Millions of dollars)
Scheduled lease payments, net of non-recourse debt	$	2,281.2	$	2,281.2
Less:    Unearned and deferred income		(973.9)		(896.8)
Investment in finance leases held in trust		1,307.3		1,384.4
Less:    Deferred income taxes		(668.4)		(772.8)
Net investment in finance leases held in trust	$	638.9	$	611.6

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

	Three months ended				Six months ended
	June 30, 2008		June 30, 2007		June 30, 2008		June 30, 2007
	(Millions of dollars)
Pre-tax earnings from PHI’s cross-border energy     lease investments (included in “Other Revenue”)	$	18.7	$	18.9	$	37.3	$	38.1
Non-cash charge to reduce equity value of     PHI’s cross-border energy lease investments		(124.4)		-		(124.4)		-
Pre-tax (loss) earnings from PHI’s cross-border     energy lease investments after adjustment		(105.7)		18.9		(87.1)		38.1
Income tax (benefit) expense		(33.7)		1.1		(29.0)		6.2
Net (loss) income from PHI’s cross-border energy     lease investments	$	(72.0)	$	17.8	$	(58.1)	$	31.9

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(6)  SEGMENT INFORMATION

Based on the provisions of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” Pepco Holdings’ management has identified its operating segments at June 30, 2008 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated.  Intrasegment revenues and expenses are eliminated at the segment level for purposes of presenting segment financial results.  Segment financial information for the three and six months ended June 30, 2008 and 2007, is as follows.

	Three Months Ended June 30, 2008
	(Millions of dollars)
				Competitive Energy Segments
	Power Delivery			Conectiv Energy			Pepco Energy Services		Other    Non-    Regulated		Corp.  & Other (a)			PHI      Cons.
Operating Revenue	$	1,296.2		$	789.7	(b)	$	631.3	$	(105.5)	(d)	$	(93.5)	$	2,518.2
Operating Expense (c)		1,143.8	(b)		748.6			605.3		.9			(94.9)		2,403.7
Operating Income		152.4			41.1			26.0		(106.4)			1.4		114.5
Interest Income		2.9			.8			.8		1.0			(.4)		5.1
Interest Expense		46.1			5.5			.6		4.8			23.1		80.1
Other Income		3.0			(.2)			.7		(.1)			.3		3.7
Preferred Stock    Dividends		-			-			-		.7			(.7)		-
Income Taxes		37.8			15.6			10.6		(27.9)	(d)		(7.9)		28.2
Net Income (loss)		74.4			20.6			16.3		(83.1)	(d)		(13.2)		15.0
Total Assets		10,054.0			2,431.2			1,000.0		1,463.8			1,416.6		16,365.6
Construction    Expenditures	$	134.2		$	43.9		$	12.1	$	-		$	4.7	$	194.9

Notes:
(a)	Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date.  Additionally, the Total Assets line item in this column includes Pepco Holdings’ goodwill balance.  Included in Corp. & Other are intercompany amounts of $(93.5) million for Operating Revenue, $(92.1) million for Operating Expense, $(12.1) million for Interest Income, $(11.4) million for Interest Expense, and $(.7) million for Preferred Stock Dividends.
(b)	Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $86.6 million for the three months ended June 30, 2008.
(c)	Includes depreciation and amortization of $92.7 million, consisting of $77.9 million for Power Delivery, $9.2 million for Conectiv Energy, $3.1 million for Pepco Energy Services, $.4 million for Other Non-Regulated, and $2.1 million for Corp. & Other.
(d)	Included in operating revenue is a pre-tax charge of $124.4 million ($86.0 million after-tax) related to the adjustment to the equity value of cross-border energy lease investments, and included in income taxes is a $6.9 million after-tax charge for the additional interest accrued on the related tax obligations.  (See Note (2), Note (5), Note (9) and Note (13) herein for additional information.)

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	Three Months  Ended June 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	$	1,162.3		$	478.2	(b)	$	522.6	$	19.1	$	(97.9)	$	2,084.3
Operating Expense (c)		1,049.2	(b)		468.1			505.9		1.1		(96.0)		1,928.3
Operating Income		113.1			10.1			16.7		18.0		(1.9)		156.0
Interest Income		1.2			1.7			.6		2.7		(2.7)		3.5
Interest Expense		45.0			8.0			.4		8.8		21.6		83.8
Other Income		5.0			-			.5		4.2		.6		10.3
Preferred Stock    Dividends		-			-			-		.6		(.5)		.1
Income Taxes		27.9			2.0			6.7		.1		(8.0)		28.7
Net Income (loss)		46.4			1.8			10.7		15.4		(17.1)		57.2
Total Assets		9,282.1			1,806.0			602.7		1,635.5		1,204.1		14,530.4
Construction    Expenditures	$	137.1		$	14.1		$	5.3	$	-	$	1.5	$	158.0

Notes:
(a)	Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date.  Additionally, the Total Assets line item in this column includes Pepco Holdings’ goodwill balance.  Included in Corp. & Other are intercompany amounts of $(97.8) million for Operating Revenue, $(96.8) million for Operating Expense, $(23.3) million for Interest Income, $(22.7) 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 $95.2 million for the three months ended June 30, 2007.
(c)	Includes depreciation and amortization of $92.7 million, consisting of $77.6 million for Power Delivery, $9.3 million for Conectiv Energy, $3.2 million for Pepco Energy Services, $.4 million for Other Non-Regulated, and $2.2 million for Corp. & Other.

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	Six Months Ended June 30, 2008
	(Millions of dollars)
				Competitive Energy Segments
	Power Delivery			Conectiv Energy			Pepco Energy Services		Other    Non-    Regulated		Corp.  & Other (a)				PHI      Cons.
Operating Revenue	$	2,591.7		$	1,612.4	(b)	$	1,252.0	$	(86.9)	(d)	$	(210.1)	$		5,159.1
Operating Expense (c)		2,334.5	(b)		1,484.6			1,212.6		2.1			(212.1)			4,821.7
Operating Income		257.2			127.8			39.4		(89.0)			2.0			337.4
Interest Income		8.8			1.5			1.2		2.0			(1.3)			12.2
Interest Expense		94.5			11.8			1.0		9.2			44.6			161.1
Other Income		7.3			(.1)			1.2		(2.5)			.7			6.6
Preferred Stock    Dividends		.1			-			-		1.4			(1.4)			.1
Income Taxes		56.9			48.4			15.9		(26.6)	(d)		(13.8)			80.8
Net Income (loss)		121.8			69.0			24.9		(73.5)	(d)		(28.0)			114.2
Total Assets		10,054.0			2,431.2			1,000.0		1,463.8			1,416.6			16,365.6
Construction    Expenditures	$	281.7		$	59.4		$	16.8	$	-		$	7.9	$		365.8

Notes:
(a)	Includes unallocated Pepco Holdings’ (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date.  Additionally, the Total Assets line item in this column includes Pepco Holdings’ goodwill balance.  Included in Corp. & Other are intercompany amounts of $(210.1) million for Operating Revenue, $(207.2) million for Operating Expense, $(28.2) million for Interest Income, $(26.8) million for Interest Expense, and $(1.4) million for Preferred Stock Dividends.
(b)	Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $184.4 million for the six months ended June 30, 2008.
(c)	Includes depreciation and amortization of $183.6 million, consisting of $154.5 million for Power Delivery, $18.4 million for Conectiv Energy, $5.9 million for Pepco Energy Services, $.9 million for Other Non-Regulated, and $3.9 million for Corp. & Other.
(d)	Included in operating revenue is a pre-tax charge of $124.4 million ($86.0 million after-tax) related to the adjustment to the equity value of cross-border energy lease investments, and included in income taxes is a $6.9 million after-tax charge for the additional interest accrued on the related tax obligations.  (See Note (2), Note (5), Note (9) and Note (13) herein for additional information.)

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	Six Months  Ended June 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	$	2,437.4		$	974.3	(b)	$	1,032.5	$	38.4	$	(219.5)	$	4,263.1
Operating Expense (c)		2,230.1	(b)		925.0			1,014.7		2.1		(217.4)		3,954.5
Operating Income		207.3			49.3			17.8		36.3		(2.1)		308.6
Interest Income		3.0			2.9			1.5		5.4		(6.0)		6.8
Interest Expense		90.5			16.4			1.7		18.0		41.8		168.4
Other Income		9.8			.1			3.8		7.5		.9		22.1
Preferred Stock    Dividends		.1			-			-		1.2		(1.1)		.2
Income Taxes		49.9			15.1			8.1		3.8		(16.8)		60.1
Net Income (loss)		79.6			20.8			13.3		26.2		(31.1)		108.8
Total Assets		9,282.1			1,806.0			602.7		1,635.5		1,204.1		14,530.4
Construction    Expenditures	$	255.4		$	20.0		$	7.0	$	-	$	2.6	$	285.0

Notes:
(a)	Includes unallocated Pepco Holdings' (parent company) capital costs, such as acquisition financing costs, and the depreciation and amortization related to purchase accounting adjustments for the fair value of Conectiv assets and liabilities as of the August 1, 2002 acquisition date.  Additionally, the Total Assets line item in this column includes Pepco Holdings' goodwill balance.  Included in Corp. & Other are intercompany amounts of $(219.5) million for Operating Revenue, $(217.2) million for Operating Expense, $(44.2) million for Interest Income, $(43.0) million for Interest Expense, and $(1.2) million for Preferred Stock Dividends.
(b)	Power Delivery purchased electric energy and capacity and natural gas from Conectiv Energy in the amount of $206.1 million for the six months ended June 30, 2007.
(c)	Includes depreciation and amortization of $185.8 million, consisting of $155.7 million for Power Delivery, $18.6 million for Conectiv Energy, $6.1 million for Pepco Energy Services, $.9 million for Other Non-Regulated and $4.5 million for Corp. & Other.

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(7)  PENSIONS AND OTHER POSTRETIREMENT BENEFITS

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

		Pension Benefits				Other Postretirement Benefits
		2008		2007		2008		2007
	(Millions of dollars)
Service cost	$	8.2	$	7.4	$	1.5	$	.9
Interest cost		28.5		26.3		10.9		8.4
Expected return on plan assets		(32.0)		(31.9)		(5.5)		(2.7)
Prior service cost/(credit) component		.1		.2		(1.1)		(1.2)
Loss component		1.7		1.0		3.9		2.4
Net periodic benefit cost	$	6.5	$	3.0	$	9.7	$	7.8

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

		Pension Benefits				Other Postretirement Benefits
		2008		2007		2008		2007
	(Millions of dollars)
Service cost	$	18.1	$	18.1	$	3.5	$	3.6
Interest cost		53.9		50.9		20.1		18.3
Expected return on plan assets		(65.0)		(65.1)		(7.9)		(6.7)
Prior service cost/(credit) component		.2		.4		(2.1)		(2.1)
Loss component		4.8		4.7		6.6		5.7
Net periodic benefit cost	$	12.0	$	9.0	$	20.2	$	18.8

Pension

The pension net periodic benefit cost for the three months ended June 30, 2008, of $6.5 million includes $3.1 million for Pepco, $.5 million for ACE, and $(1.4) million for DPL.  The pension net periodic benefit cost for the six months ended June 30, 2008, of $12.0 million includes $5.7 million for Pepco, $1.3 million for ACE, and $(2.7) million for DPL.  The pension net periodic benefit cost for the three months ended June 30, 2007, of $3.0 million includes $1.4 million for Pepco, $.3 million for ACE, and $(1.3) million for DPL.  The pension net periodic benefit cost for the six months ended June 30, 2007, of $9.0 million includes $4.5 million for Pepco, $1.3 million for ACE, and $(2.8) 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

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elect, however, to make a discretionary tax-deductible contribution to maintain the pension plan’s assets in excess of its ABO.  As of June 30, 2008 and 2007, no contributions were made, for the respective years.  The potential discretionary funding of the pension plan in 2008 will depend on many factors for the respective years, 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 June 30, 2008, of $9.7 million includes $2.7 million for Pepco, $2.2 million for ACE and $2.2 million for DPL.  The other postretirement net periodic benefit cost for the six months ended June 30, 2008, of $20.2 million includes $6.4 million for Pepco, $4.6 million for ACE and $4.4 million for DPL.  The other postretirement net periodic benefit cost for the three months ended June 30, 2007, of $7.8 million includes $1.8 million for Pepco, $2.0 million for ACE and $2.2 million for DPL.  The other postretirement net periodic benefit cost for the six months ended June 30, 2007, of $18.8 million includes $6.7 million for Pepco, $4.4 million for ACE and $4.0 million for DPL.  The remaining other postretirement net periodic benefit cost is for other PHI subsidiaries.

(8)  DEBT

In April 2008, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $5.1 million on Series 2002-1 Bonds, Class A-1 and $2.1 million on Series 2003-1.

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

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

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

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

During the first quarter of 2008, PHI subsidiaries purchased at par $82.75 million in aggregate principal of insured tax-exempt auction rate bonds issued by municipal authorities for the benefit of the respective PHI subsidiaries.  These purchases were made in response to disruption in the market for municipal auction rate securities that made it difficult for the remarketing agent to successfully remarket the bonds.  During the second quarter of 2008, PHI subsidiaries purchased at par additional insured tax-exempt auction rate bonds in the aggregate principal amount of $174.8 million as follows:

·   In April 2008, Pepco purchased $109.5 million of Pollution Control Revenue Refunding Bonds Series 2006 due 2022 issued by the Maryland Economic Development Corporation.

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·   In April 2008, ACE purchased the following series of bonds:  (i) $23.15 million of Pollution Control Revenue Refunding Bonds Series 2004A due 2029 issued by Salem County and (ii) $6.5 million of Pollution Control Revenue Refunding Bonds Series 2004B due 2029 issued by Cape May County.

·   In April 2008, DPL purchased the following series of bonds issued by the Delaware Economic Development Authority:  (i) $20 million of Exempt Facilities Refunding Revenue Bonds 2001A Series due 2031, (ii) $4.5 million of Exempt Facilities Refunding Revenue Bonds 2001B Series due 2031, and (iii) $11.15 million of Exempt Facilities Refunding Revenue Bonds 2000A Series due 2030.

These bonds are considered to be extinguished for accounting purposes; however each of the companies intends to hold the bonds, while monitoring the market and evaluating the options for remarketing the bonds to the public at some time in the future.

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

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

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

The payment for these VRDBs was financed by The Bank of New Yorkunder Standby Bond Purchase Agreements for the respective series (SBPAs).  If these VRDBs cannot be remarketed by the remarketing agent prior to the first anniversary of the purchase of the VRDBs by the bond trustee, ACE will be obligated to redeem 1/10th of the principal amount of each series of VRDBs held by the bond trustee every six months thereafter.  While the VRDBs are held by the bond trustee, ACE is obligated to pay interest on such bonds at a rate equal to the prime rate or Libor plus 50 basis points.

           During the second quarter of 2008, ACE redeemed at maturity the following Medium Term Notes:

·    In April 2008, $1 million of 6.77% Medium Term Notes.

·   In May 2008, (i) $21 million of 6.75% Medium Term Notes and (ii) $4 million of 6.73% Medium Term Notes.

·   In June 2008, (i) $4 million of 6.73% Medium Term Notes and (ii) $5 million of 6.71% Medium Term Notes.

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

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(9)  INCOME TAXES

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2008		2007		2008		2007
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	3.9		2.7		1.7		2.5
Asset removal costs	(1.4)		(.6)		(1.1)		(.7)
State income taxes, net of federal effect	22.2		3.0		9.1		3.8
Tax credits	(2.5)		(1.4)		(1.1)		(1.4)
PHI’s cross-border energy lease investments	9.0		(2.2)		1.1		(2.2)
Change in estimates and interest related to uncertain         and effectively settled tax positions	3.9		(2.7)		(2.7)		(1.4)
Software amortization	1.2		.8		.6		.9
State interest refund	(5.3)		-		(1.2)		-
Other, net	(.7)		(1.2)		-		(1.0)
Consolidated Effective Income Tax Rate	65.3	%	33.4	%	41.4	%	35.5	%

PHI’s effective tax rates for the three months ended June 30, 2008 and 2007 were 65.3% and 33.4%, respectively.  The increase in the effective tax rate was primarily driven by limited state tax benefits related to the charge taken on the cross-border energy lease investments as further discussed in Note (2) and Note (13).  In addition, the change in the rate was affected by a substantial increase in interest on uncertain tax positions related to the cross-border energy lease investments and certain prior period adjustments for Pepco.  These changes were offset by interest benefits related to uncertain tax positions recorded for the tentative settlement with the IRS on the mixed service cost issue (as further discussed below and in Note (13)), and the June 2008 receipt of interest of $3.5 million ($2.2 million after-tax) from the state of Maryland with respect to a tax refund received during the third quarter of 2007.

PHI’s effective tax rates for the six months ended June 30, 2008 and 2007 were 41.4% and 35.5%, respectively.  The increase in the effective tax rate was primarily driven by limited state tax benefits related to the charge taken on the cross-border energy lease investments as further discussed in Note (2) and Note (13).  In addition, the change in the rate was affected by a substantial increase in interest on uncertain tax positions related to the cross-border energy lease investments and certain prior period adjustments for Pepco.  These changes were offset by interest benefits related to uncertain tax positions recorded for the tentative settlement with the IRS on the mixed service cost issue (as further discussed below and in Note (13)) casualty loss deduction claims filed with the IRS in March 2008 and the June 2008 receipt of interest of $3.5 million ($2.2 million after-tax) from the State of Maryland with respect to a tax refund received during the third quarter of 2007.

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

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(10)  STOCK-BASED COMPENSATION

No stock options were granted in the six months ended June 30, 2008.

Cash received from options exercised under all share-based payment arrangements for the three months ended June 30, 2008, was $2.1 million and the actual tax benefit realized for the tax deductions resulting from these options exercised was minimal. Cash received from options exercised under all share-based payment arrangements for the six months ended June 30, 2008, was $2.9 million and the actual tax benefit realized for the tax deductions resulting from these options exercised totaled $.2 million.

(11) EARNINGS PER SHARE

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

	For the Three Months Ended June 30,
			2008		2007
	(In millions, except per share data)
Income (Numerator):
Net Income		$	15.0	$	57.2
Add:    Loss on redemption of subsidiary’s preferred stock			-		-
Earnings Applicable to Common Stock		$	15.0	$	57.2
Shares (Denominator) (a):
Weighted average shares outstanding for basic computation:
Average shares outstanding			201.4		193.2
Adjustment to shares outstanding			(.3)		(.2)
Weighted Average Shares Outstanding for Computation of   Basic Earnings Per Share of Common Stock			201.1		193.0
Net effect of potentially dilutive shares			.4		.5
Weighted Average Shares Outstanding for Computation of   Diluted Earnings Per Share of Common Stock			201.5		193.5
Basic earnings per share of common stock		$	.07	$	.30
Diluted earnings per share of common stock		$	.07	$	.30

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS as they are considered to be anti-dilutive were approximately 5,000 and 8,000 for the three months ended June 30, 2008 and 2007, respectively.

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	For the Six Months Ended June 30,
			2008		2007
	(In millions, except per share data)
Income (Numerator):
Net Income		$	114.2	$	108.8
Add:    Loss on redemption of subsidiary’s preferred stock			-		(.6)
Earnings Applicable to Common Stock		$	114.2	$	108.2
Shares (Denominator) (a):
Weighted average shares outstanding for basic computation:
Average shares outstanding			201.2		192.8
Adjustment to shares outstanding			(.3)		(.2)
Weighted Average Shares Outstanding for Computation of   Basic Earnings Per Share of Common Stock			200.9		192.6
Net effect of potentially dilutive shares			.3		.5
Weighted Average Shares Outstanding for Computation of   Diluted Earnings Per Share of Common Stock			201.2		193.1
Basic earnings per share of common stock		$	.57	$	.56
Diluted earnings per share of common stock		$	.57	$	.56

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS as they are considered to be anti-dilutive were 5,000 and 8,000 for the six months ended June 30, 2008 and 2007, respectively.

(12)  FAIR VALUE DISCLOSURES

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

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

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

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

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

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

The following table sets forth by level within the fair value hierarchy PHI's financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2008.  As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  PHI's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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	Fair Value Measurements at Reporting Date Using
	(Millions of dollars)
Description	June 30, 2008	Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level  3)
ASSETS
Derivative Instruments	$785.3	$220.2		$541.9	(b)	$23.2
Executive deferred   compensation plan assets	70.0	-		51.7		18.3
	$855.3	$220.2		$593.6		$41.5
LIABILITIES
Derivative Instruments	$173.8	$(36.3)	(a)	$208.1		$ 2.0
Executive deferred   compensation plan liabilities	38.1	-		38.1		-
	$211.9	$(36.3)		$246.2		$ 2.0

(a) Includes contra-liability balance of $42.9 million related to the impact of netting certain counterparties across the levels of the fair value hierarchy.

(b) Includes contra-asset balance of $3.3 million related to impact of netting certain counterparties across the levels of the fair value hierarchy.

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

	Net Derivative Instruments	Deferred Compensation Plan Assets
Beginning balance as of January 1, 2008	$   .6	$17.1
Total gains or (losses) (realized/unrealized)
Included in earnings	28.2	1.8
Included in other comprehensive income	3.7	-
Purchases and issuances	-	-
Settlements	(.9)	(.6)
Transfers in and/or out of Level 3	(10.4)	-
Ending balance as of June 30, 2008	$21.2	$18.3
Gains (realized and unrealized) included in earnings for the period above are reported in Operating Revenue and Other Operation and Maintenance Expense as follows:	Operating Revenue	Other Operation and Maintenance Expense
Total gains included in earnings for the period above	$28.2	$  1.8
Change in unrealized gains relating to assets still held at reporting date	$25.1	$  1.8

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(13)  COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Proceeds from Settlement of Mirant Bankruptcy Claims

In 2000, Pepco sold substantially all of its electricity generating assets to Mirant and certain of its subsidiaries.  In 2003, Mirant commenced a voluntary bankruptcy proceeding in which it sought to reject certain obligations that it had undertaken in connection with the asset sale.  As part of the sale, Pepco and Mirant entered into a “back-to-back” arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco is obligated to purchase annually through 2021 from Panda under the Panda PPA at the purchase price Pepco is obligated to pay to Panda.  In connection with the settlement of Pepco’s claims against Mirant arising from the Mirant bankruptcy, Pepco agreed not to contest the rejection by Mirant of its obligations under the “back-to-back” arrangement in exchange for the payment by Mirant of damages corresponding to the estimated amount by which the purchase price that Pepco is obligated to pay Panda for the energy and capacity exceeded the market price.  In 2007, Pepco received as damages $413.9 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant.  These funds are being accounted for as restricted cash based on management’s intent to use such funds, and any interest earned thereon, for the sole purpose of paying for the future above-market capacity and energy purchase costs under the Panda PPA.  Correspondingly, a regulatory liability has been established in the same amount to help offset the future above-market capacity and energy purchase costs.  This restricted cash has been classified as a non-current asset to be consistent with the classification of the non-current regulatory liability, and any changes in the balance of this restricted cash, including interest on the invested funds, are being accounted for as operating cash flows.  As of June 30, 2008, the balance of the restricted cash account was approximately $412 million.

On June 20, 2008, Pepco entered into an agreement with Panda and Sempra Energy Trading LLC (Sempra) under which Pepco has agreed, in exchange for a payment from Pepco to Sempra, to transfer the Panda PPA to Sempra (the Transfer Agreement).  Upon closing of the transaction, Pepco will have no further rights and obligations under the Panda PPA.  The closing of the transaction is subject to various conditions.  In the event the closing does not occur on or before September 22, 2008, any party to the Transfer Agreement has the right to terminate the transaction.

In view of the entry into the Transfer Agreement, Pepco has withdrawn previous applications filed with the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC) requesting orders directing it to place $320 million of the damages received from Mirant in a special purpose account to be used solely for paying the future above-market cost of the Panda PPA.  Following the transfer of the Panda PPA, Pepco intends to file revised rates with the DCPSC and the MPSC for the purpose of distributing the remaining funds in the restricted cash account after deducting the payment made to Sempra under the Transfer Agreement.  The portion of the balance of the funds in the restricted cash account that Pepco ultimately retains will depend on the customer sharing arrangements approved by the DCPSC and the MPSC.

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Rate Proceedings

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

District of Columbia

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

Maryland

In July 2007, the MPSC issued orders in the electric service distribution rate cases filed by DPL and Pepco, each of which included approval of a BSA.  The DPL order approved an annual increase in distribution rates of approximately $14.9 million (including a decrease in annual depreciation expense of approximately $.9 million).  The Pepco order approved an annual increase in distribution rates of approximately $10.6 million (including a decrease in annual depreciation expense of approximately $30.7 million).  In each case, the approved distribution rate reflects an ROE of 10.0%.  The rate increases were effective as of June 16, 2007, and remained in effect for an initial period until July 19, 2008, pending a Phase II proceeding in which the MPSC considered the results of audits of each company’s cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates was required.  On July 18, 2008, the MPSC issued one order covering the Phase II proceedings for both DPL and Pepco, denying any further adjustment to the rates for each company, thus making permanent the rate increases approved in the July 2007 orders.

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New Jersey

In June 2007, ACE filed with the New Jersey Board of Public Utilities (NJBPU) an application for permission:

·   to decrease the Non Utility Generation Charge, which is intended primarily to allow ACE to recover the above-market component of payments made by ACE under non-utility generation contracts and stranded costs associated with those commitments (NGC), which had an over-recovery balance, and

·   to increase components of its Societal Benefits Charge, which is intended to allow ACE to recover certain costs involved with various NJBPU-mandated social programs (SBC), which had an under-recovery balance.

In an order dated May 20, 2008, the NJBPU approved a Stipulation of Settlement under which the net impact of the adjustments to the NGC and the SBC, including associated changes in sales and use tax, is an overall rate decrease of approximately $117.3 million over the period June 1, 2008 through May 31, 2009 (the final rate changes will be based upon actual data through March 2008).  ACE anticipates that the revised rates will remain in effect until May 31, 2009, subject to an annual true-up and change each year thereafter.

Divestiture Cases

District of Columbia

In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets.  An unresolved issue relating to the application filed with the DCPSC by Pepco to implement the divestiture settlement is whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code (IRC) and its implementing regulations.  As of June 30, 2008, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6.5 million and $5.8 million, respectively.  Other issues in the divestiture proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.

Pepco believes that a sharing of EDIT and ADITC would violate the IRS normalization rules.  Under these rules, Pepco could not transfer the EDIT and the ADITC benefit to customers more quickly than on a straight line basis over the book life of the related assets.  Since the assets are no longer owned by Pepco, there is no book life over which the EDIT and ADITC can be returned.  If Pepco were required to share EDIT and ADITC and, as a result, the normalization rules were violated, Pepco would be unable to use accelerated depreciation on District of Columbia allocated or assigned property.  In addition to sharing with customers the generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS an amount equal to Pepco’s District of Columbia jurisdictional generation-related ADITC balance ($5.8 million as of June 30, 2008), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3.7 million as of June 30, 2008) in each case as those

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balances exist as of the later of the date a DCPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the DCPSC order becomes operative.

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

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

Maryland

Pepco filed its divestiture proceeds plan application with the MPSC in April 2001.  The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that has been raised in the District of Columbia case.  See the discussion above under “Divestiture Cases --- District of Columbia.”  As of June 30, 2008, the Maryland allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $9.1 million and $10.4 million, respectively.  Other issues deal with the treatment of certain costs as deductions from the gross proceeds of the divestiture.  In November 2003, the Hearing Examiner in the Maryland proceeding issued a proposed order with respect to the application that concluded that Pepco’s Maryland divestiture settlement agreement provided for a sharing between Pepco and customers of the EDIT and ADITC associated with the sold assets.  Pepco believes that such a sharing would violate the normalization rules (as discussed above) and would result in Pepco’s inability to use accelerated depreciation on Maryland allocated or assigned property.  If the proposed order is affirmed, Pepco would have to share with its Maryland customers, on an approximately 50/50 basis, the Maryland allocated portion of the generation-related EDIT ($9.1 million as of June 30, 2008), and the Maryland-allocated portion of generation-related ADITC.  Furthermore, Pepco would have to pay to the IRS an amount equal to Pepco’s Maryland jurisdictional generation-related ADITC balance ($10.4 million as of June 30, 2008), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($6.6 million as of June 30, 2008), in each case as those balances exist as of the later of the date a MPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the MPSC order becomes operative.  The Hearing Examiner decided all other issues in favor of Pepco, except for the determination that only one-half of the severance payments that Pepco

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included in its calculation of corporate reorganization costs should be deducted from the sales proceeds before sharing of the net gain between Pepco and customers.

In December 2003, Pepco appealed the Hearing Examiner’s decision to the MPSC as it relates to the treatment of EDIT and ADITC and corporate reorganization costs.  The MPSC has not issued any ruling on the appeal, pending completion of the IRS rulemaking regarding sharing of EDIT and ADITC related to divested assets.  Pepco made a filing on April 22, 2008, advising the MPSC of the adoption of the final IRS normalization regulations (described above under “Divestiture Cases -- District of Columbia”) and requesting that the MPSC issue a ruling on the appeal consistent with the IRS position.  If the MPSC issues the requested ruling, no accounting adjustments to the gain recorded in 2000 would be required.  However, neither PHI nor Pepco believes that additional gain-sharing payments, if any, or the ADITC-related payments to the IRS, if required, would have a material adverse impact on its financial position or cash flows.

ACE Sale of B.L. England Generating Facility

In February 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy Investments, LLC.  In July 2007, ACE received a claim for indemnification from RC Cape May under the purchase agreement in the amount of $25 million.  RC Cape May contends that one of the assets it purchased, a contract for terminal services (TSA) between ACE and Citgo Asphalt Refining Co. (Citgo), has been declared by Citgo to have been terminated due to a failure by ACE to renew the contract in a timely manner.  RC Cape May has commenced an arbitration proceeding against Citgo seeking a determination that the TSA remains in effect and has notified ACE of the proceeding.  The claim for indemnification seeks payment from ACE in the event the TSA is held not to be enforceable against Citgo.  While ACE believes that it has defenses to the indemnification claim, should the arbitrator rule that the TSA has terminated, the outcome of this matter is uncertain.  ACE notified RC Cape May of its intent to participate in the pending arbitration.

DPL Sale of Virginia Operations

In January 2008, DPL completed (i) the sale of its retail electric distribution business on the Eastern Shore of Virginia to A&N Electric Cooperative (A&N) for a purchase price of approximately $48.8 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission business located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase price of approximately $5.4 million, after closing adjustments.  Each of A&N and ODEC assumed certain post-closing liabilities and unknown pre-closing liabilities related to the respective assets they purchased (including, in the A&N transaction, most environmental liabilities), except that DPL remained liable for unknown pre-closing liabilities if they become known within six months after the January 2, 2008 closing date.  The allowance period for A&N and/or ODEC to notify DPL has passed and no notification was made with respect to the discovery of additional pre-closing liabilities.  A&N has delayed final payment of approximately $3.5 million, which was due on June 2, 2008, due to a dispute in the final true-up amounts.  DPL is in discussions with A&N to resolve the issues.  DPL can not predict the outcome of these discussions.

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General Litigation

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

Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed.  As a result of two motions to dismiss, numerous hearings and meetings and one motion for summary judgment, Pepco has had approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court.  As of June 30, 2008, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement between Pepco and Mirant under which Pepco sold its generation assets to Mirant in 2000.

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

Cash Balance Plan Litigation

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

The plaintiffs challenged the design of the Cash Balance Sub-Plan and sought a declaratory judgment that the Cash Balance Sub-Plan was invalid and that the accrued benefits

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of each member of the class should be calculated pursuant to the terms of the predecessor plans.  Specifically, the complaint alleged that the use of a variable rate to compute the plaintiffs’ accrued benefit under the Cash Balance Sub-Plan resulted in reductions in the accrued benefits that violated ERISA.  The complaint also alleged that the benefit accrual rates and the minimal accrual requirements of the Cash Balance Sub-Plan violated ERISA as did the notice that was given to plan participants upon implementation of the Cash Balance Sub-Plan.

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

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.

Delilah Road Landfill Site.  In 1991, the New Jersey Department of Environmental Protection (NJDEP) identified ACE as a potentially responsible party (PRP) at the Delilah Road Landfill site in Egg Harbor Township, New Jersey.  In 1993, ACE, along with other PRPs, signed an administrative consent order with NJDEP to remediate the site.  The soil cap remedy for the site has been implemented and in August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site.  Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years.  In September 2007, NJDEP approved the PRP group’s petition to conduct semi-annual, rather than quarterly, ground water monitoring for two years and deferred until the end of the two-year period a decision on the PRP group’s request for annual groundwater monitoring thereafter.  In August 2007, the PRP group agreed to reimburse the costs of the U.S. Environmental Protection Agency (EPA) in the amount of $81,400 in full satisfaction of EPA’s claims for all past and future response costs relating to the site (of which

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ACE’s share is one-third).  Effective April 11, 2008, EPA and the PRP group entered into a settlement agreement which will allow EPA to reopen the settlement in the event of new information or unknown conditions at the site.  Based on information currently available, ACE anticipates that its share of additional cost associated with this site for post-remedy operation and maintenance will be approximately $555,000 to $600,000.  ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial position, results of operations or cash flows.

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

Carolina Transformer Site.  In August 2006, EPA notified each of DPL and Pepco that they have been identified as entities that sent PCB-laden oil to be disposed at the Carolina Transformer site in Fayetteville, North Carolina.  The EPA notification stated that, on this basis, DPL and Pepco may be PRPs.  In early 2008, EPA, the PRP group and the State of North Carolina entered into a settlement agreement under which (i) Pepco and DPL each paid $162,000 to resolve any liability that it might have at the site to EPA and the State of North Carolina, (ii) EPA and the State of North Carolina covenanted not to sue or bring administrative action against DPL and Pepco for response costs at the site, (iii) other PRP group members released all rights for cost recovery or contribution claims they may have against DPL and Pepco, and (iv) DPL and Pepco released all rights for cost recovery or contribution claims that they may have against other parties settling with EPA and the State of North Carolina.  The consent decree related to the settlement agreement was lodged with the U.S. District Court for the Eastern District of North Carolina on June 6, 2008.  No comments were filed during the public notice and comment period, which expired on July 16, 2008, and on July 30, 2008, EPA and the State of North Carolina filed their motion requesting the court to enter the consent decree.

IRS Examination of Like-Kind Exchange Transaction

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

The transaction was examined by the IRS as part of the normal Conectiv tax audit.  In May 2006, the IRS issued a revenue agent’s report (RAR) for the audit of Conectiv’s 2000, 2001 and 2002 income tax returns, in which the IRS disallowed the qualification of the

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exchange under IRC Section 1031.  In July 2006, Conectiv filed a protest of this disallowance to the U.S. Office of Appeals of the IRS (Appeals Office).

PHI believes that its tax position related to this transaction is proper based on applicable statutes, regulations and case law and is contesting the disallowance.  However, there is no assurance that Conectiv’s position will prevail.  If the IRS prevails, Conectiv would be subject to additional income taxes, interest and possible penalties.  However, a portion of the denied benefit would be offset by additional tax depreciation.  PHI has accrued approximately $5.5 million of interest reserves related to this matter.

As of June 30, 2008, if the IRS were to fully prevail, the potential cash impact on PHI would be current income tax and interest payments of approximately $29.5 million and the earnings impact would be a charge of approximately $11.1 million in after-tax interest.

PHI’s Cross-Border Energy Lease Investments

Between 1994 and 2002, Potomac Capital Investment Corporation (PCI), a subsidiary of PHI, entered into eight cross-border energy lease investments involving public utility assets (primarily consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks) located outside of the United States.  Each of these investments is structured as a sale and leaseback transaction commonly referred to as a SILO transaction.  Historically, PHI has derived approximately $74 million per year in tax benefits from these eight cross-border energy lease investments (reflecting 100% of the tax benefits) to the extent that rental income under the leases is exceeded by the depreciation deductions on the purchase price of the assets and interest deductions on the non-recourse debt financing (obtained by PCI to fund a substantial portion of the purchase price of the assets).  As of June 30, 2008, PHI’s equity investment in its cross-border energy leases was approximately $1.3 billion which included the effect of the reassessment discussed below.  During the period from January 1, 2001 through June 30, 2008, PHI has derived approximately $458 million in federal income tax benefits from the depreciation and interest deductions in excess of rental income with respect to these cross-border energy lease investments.

In 2005, the Treasury Department and IRS issued Notice 2005-13 identifying sale-leaseback transactions with certain attributes entered into with tax-indifferent parties as tax avoidance transactions, and the IRS announced its intention to disallow the associated tax benefits claimed by the investors in these transactions.  PHI’s cross-border energy lease investments, each of which is with a tax-indifferent party, have been under examination by the IRS as part of the normal PHI federal income tax audits.  In the final RAR issued in June 2006 in connection with the audit of PHI’s 2001 and 2002 income tax returns, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to six of its cross-border energy lease investments.  In addition, the IRS has sought to recharacterize the leases as loan transactions as to which PHI would be subject to original issue discount income.  PHI is protesting the IRS adjustments and the unresolved audit issues have been forwarded to the Appeals Office.  PHI is in the early stages of discussions with the Appeals Office.  If these discussions are unsuccessful, PHI currently intends to pursue litigation proceedings against the IRS to defend its tax position.  While the audits of PHI’s federal income tax returns for subsequent tax years are ongoing or have not yet commenced, PHI anticipates that the IRS will take the same position with respect to each of the subsequent years on all eight of its cross-border energy lease investments.

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

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

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

·   A non-cash charge of $6.9 million after-tax to reflect the anticipated additional interest expense under FIN 48 on the estimated federal and state income tax that would be payable for the period January 1, 2001 through June 30, 2008, based on the revised assumptions regarding the estimated timing of the tax benefits.  This after-tax charge has been recorded in the Consolidated Statement of Earnings as an increase in income tax expense.

The charge pursuant to FSP 13-2 reflects changes to the book equity value of the cross-border energy lease investments and the pattern of recognizing the related cross-border energy lease income.  This amount will be recognized as income over the remaining term of the affected leases, which expire between 2017 and 2047.  The tax benefits associated with the lease transactions represent timing differences that do not change the aggregate amount of the lease net income over the life of the transactions.  Under these revised assumptions, the additional federal and state income taxes at June 30, 2008 would have been approximately $107.4 million along with an after-tax interest payment of approximately $10.0 million.

PHI has made no cash payments of federal or state income taxes or interest thereon as a result of the reassessment discussed above and the related change in assumptions regarding the estimated timing of the tax benefits.  Whether PHI makes a payment, and the amount and the

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timing thereof, will depend on a number of factors, including PHI’s litigation strategy, whether a settlement with the IRS can be reached or whether the company decides to deposit funds with the IRS to avoid higher interest costs, until the issue is resolved.  PHI is continuing to defend vigorously its tax position with the IRS.

If PHI had recalculated the value of its equity investment in its cross-border energy lease investments as of June 30, 2008, to reflect the changes in cash flow resulting from the disallowance of the entire amount of the tax benefits from the depreciation and interest deductions in excess of rental income over the period from January 1, 2001 through the end of the lease term and the recharacterization of the transactions as loans, the result would have been an additional non-cash charge to earnings of approximately $346.3 million consisting of:

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

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

In addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due.  The charges pursuant to FSP 13-2 reflect changes to the book equity value of the cross-border energy lease investments and the pattern of recognizing the related cross-border energy lease income.  This amount will be recognized as income over the remaining term of the affected leases, which expire between 2017 and 2047.  PHI anticipates that any additional taxes that it would be required to pay as a result of the disallowance of prior deductions or a recharacterization of leases as loans would be recoverable in the form of lower taxes over the remaining term of the investments.

In the event of the total disallowance of the tax benefits and the imputing of original issue discount income due to the recharacterization of the leases as loans, PHI would have been obligated to pay, as of June 30, 2008, approximately $510.2 million in additional federal and state taxes (including the $458 million of tax benefits received from 2001 to date) and $63.3 million of interest (which amounts include $107.4 million of federal and state income taxes and $10 million of interest referred to earlier in relation to the charge recorded).

In early August, the IRS announced that it is sending global settlement offers to many taxpayers with LILO and SILO investments.  PHI received a settlement offer letter on August 7, 2008 and is evaluating the offer.

Potential Legislation Affecting the Tax Treatment of Cross-Border Leases

On June 18, 2008, the Farm, Nutrition and Bioenergy Act of 2007 became law and excluded an earlier provision that would have applied passive loss limitation rules to leases with foreign tax indifferent parties effective for taxable years beginning after December 31, 2006.  The provision, if included, could have resulted in a material delay of the income tax benefits that PHI would receive in connection with its cross-border energy leases.  At this time, PHI is not aware of any pending legislation that would propose passive loss limitations for leases with foreign tax-indifferent parties.

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IRS Mixed Service Cost Issue

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

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

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

In February 2006, PHI paid approximately $121 million of taxes to cover the amount of additional taxes and interest that management estimated to be payable for the years 2001 through 2004 based on the method of tax accounting that PHI, pursuant to the proposed regulations, adopted on its 2005 tax return.  In June 2008, PHI received from the Appeals Office an offer of settlement pertaining to each of Pepco, DPL and ACE for the tax years 2001 through 2004.  PHI is substantially in agreement with this proposed settlement.  Based on the terms of the proposal, PHI expects the final settlement amount to be less than the $121 million previously deposited.  Accordingly, in the quarter ended June 30, 2008, PHI recorded after-tax interest income of $7.2million and a net reduction in its liability for unrecognized tax benefits of $18.7 million.

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

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

As of June 30, 2008, Pepco Holdings and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, performance residual value, and other commitments and obligations.  The commitments and obligations, in millions of dollars, were as follows:

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	Guarantor
		PHI		DPL		ACE		Other		Total
Energy marketing obligations of Conectiv Energy (a)	$	418.9	$	-	$	-	$	-	$	418.9
Energy procurement obligations ofPepco Energy Services (a)		114.8		-		-		-		114.8
Guaranteed lease residual values (b)		-		2.9		2.6		.6		6.1
Other (c)		2.0		-		-		1.1		3.1
Total	$	535.7	$	2.9	$	2.6	$	1.7	$	542.9

(a)	Pepco Holdings has contractual commitments for performance and related payments of Conectiv Energy and Pepco Energy Services to counterparties under routine energy sales and procurement obligations, including retail customer load obligations of Pepco Energy Services and requirements under BGS contracts entered into by Conectiv Energy with ACE.
(b)	Subsidiaries of Pepco Holdings have guaranteed residual values in excess of fair value of certain equipment and fleet vehicles held through lease agreements. As of June 30, 2008, obligations under the guarantees were approximately $6.1 million. Assets leased under agreements subject to residual value guarantees are typically for periods ranging from 2 years to 10 years. Historically, payments under the guarantees have not been made by the guarantor as, under normal conditions, the contract runs to full term at which time the residual value is minimal. As such, Pepco Holdings believes the likelihood of payment being required under the guarantee is remote.
(c)	Other guarantees consist of:

· Pepco Holdings has guaranteed a subsidiary building lease of $2.0 million. Pepco Holdings does not expect to fund the full amount of the exposure under the guarantee.  

· PCI has guaranteed facility rental obligations related to contracts entered into by Starpower Communications, LLC, a joint venture in which PCI prior to December 2004 had a 50% interest. As of June 30, 2008, the guarantees cover the remaining $1.1 million in rental obligations.

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

Dividends

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

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

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

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The table below provides detail on effective cash flow hedges under SFAS No. 133 included in PHI’s Consolidated Balance Sheet as of June 30, 2008.  Under SFAS No. 133, cash flow hedges are marked-to-market on the balance sheet with corresponding adjustments to Accumulated Other Comprehensive Income (AOCI).  The data in the table indicates the magnitude of the effective cash flow hedges by hedge type (i.e., energy commodity and interest rate hedges), maximum term, and portion expected to be reclassified to earnings during the next 12 months.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income As of June 30, 2008 (Millions of dollars)
Contracts	Accumulated OCI (Loss) After-tax (a)		Portion Expected to be Reclassified to Earnings during the Next 12 Months		Maximum Term
Energy Commodity Activities	$	320.2	$	229.1	47 months
Interest Rate		(27.2)		(3.3)	290 months
Total	$	293.0	$	225.8

(a) Accumulated Other Comprehensive Income as of June 30, 2008, includes a $(10.4) million balance related to minimum pension liability.  This balance is not included in this table as there is not a cash flow hedge associated with it.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
Operating Revenue	$	4.0	$	(.1)	$	1.3	$	(.7)
Fuel and Purchased Energy Expenses		3.3		.3		9.1		-
Total	$	7.3	$	.2	$	10.4	$	(.7)

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 six months ended June 30, 2008 and 2007, and included in the Consolidated Statements of Earnings for fair value hedges and the associated hedged items are shown in the following table (in millions of dollars).

	Three Months Ended June 30,				Six Months Ended June 30,
		2008		2007		2008		2007
(Loss) Gain on Derivative Instruments	$	(24.2)	$	.4	$	(35.0)	$	(1.4)
Gain (Loss) on Hedged Items	$	21.2	$	(.5)	$	32.5	$	1.1

For the three and six months ended June 30, 2008, $5.3 million and $5.8 million, respectively, in gains were reclassified from Other Comprehensive Income (OCI) to earnings

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because the forecasted hedged transactions were deemed to be no longer probable.  For the three and six months ended June 30, 2007, $1.6 million and $.4 million, respectively, in losses were reclassified from OCI to earnings because the forecasted hedged transactions were deemed to be no longer probable.

In connection with their energy commodity activities, the Competitive Energy businesses hold certain derivatives that do not qualify as hedges.  Under SFAS No. 133, these derivatives are 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 six months ended June 30, 2008 and 2007.

Energy Commodity Activities (a)	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
Realized Gains (Losses)	$	8.6	$	8.5	$	24.8	$	25.3
Unrealized Gains (Losses)		(5.2)		.5		22.6		(8.3)
Total	$	3.4	$	9.0	$	47.4	$	17.0

(a) Includes $.1 million and $.5 million of ineffective fair value hedge gains for the three and six months ended June 30, 2007, respectively.

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

	June 30, 2008		December 31, 2007
	(Millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	31.1	$	-
Cash collateral received from counterparties with the obligation to return		308.0		-

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

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POTOMAC ELECTRIC POWER COMPANY STATEMENTS OF EARNINGS (Unaudited)
	Three Months Ended June 30,				Six Months Ended June 30,
		2008		2007		2008		2007
		(Millions of dollars)
Operating Revenue	$	538.9	$	495.0	$	1,063.4	$	1,001.6
Operating Expenses
Fuel and purchased energy		293.8		264.3		601.3		560.8
Other operation and maintenance		76.7		71.3		147.0		142.3
Depreciation and amortization		34.8		42.0		69.2		83.9
Other taxes		69.4		72.0		139.0		140.3
Gain on sale of assets		-		-		-		(.6)
Total Operating Expenses		474.7		449.6		956.5		926.7
Operating Income		64.2		45.4		106.9		74.9
Other Income (Expenses)
Interest and dividend income		2.2		.3		6.2		.8
Interest expense		(22.8)		(18.3)		(46.8)		(36.8)
Other income		2.2		3.4		5.0		6.5
Other expenses		(.2)		(.1)		(.3)		(.2)
Total Other Expenses		(18.6)		(14.7)		(35.9)		(29.7)
Income Before Income Tax Expense		45.6		30.7		71.0		45.2
Income Tax Expense		14.2		12.7		24.4		18.5
Net Income		31.4		18.0		46.6		26.7
Retained Earnings at Beginning of Period		592.1		551.5		596.9		559.7
Dividends Paid to Pepco Holdings		-		(14.0)		(20.0)		(29.0)
Cumulative Effect Adjustment Related to   the Implementation of FIN 48		-		-		-		(1.9)
Retained Earnings at End of Period	$	623.5	$	555.5	$	623.5	$	555.5

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

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POTOMAC ELECTRIC POWER COMPANY BALANCE SHEETS (Unaudited)
ASSETS		June 30, 2008		December 31, 2007
	(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$	16.2	$	19.0
Restricted cash			18.2		1.2
Accounts receivable, less allowance for  uncollectible accounts     of $12.6 million and $12.5 million, respectively			365.0		343.5
Materials and supplies - at average cost			48.8		45.4
Prepayments of income taxes			70.5		93.4
Prepaid expenses and other			14.9		15.1
Total Current Assets			533.6		517.6
INVESTMENTS AND OTHER ASSETS
Regulatory assets			210.5		178.5
Prepaid pension expense			147.1		152.0
Investment in trust			26.3		26.5
Income taxes receivable			173.1		171.2
Restricted cash and cash equivalents			411.9		417.3
Other			72.6		75.4
Total Investments and Other Assets			1,041.5		1,020.9
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			5,471.7		5,368.9
Accumulated depreciation			(2,317.6)		(2,274.4)
Net Property, Plant and Equipment			3,154.1		3,094.5
TOTAL ASSETS		$	4,729.2	$	4,633.0

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

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POTOMAC ELECTRIC POWER COMPANY BALANCE SHEETS (Unaudited)
LIABILITIES AND SHAREHOLDER’S EQUITY		June 30, 2008		December 31, 2007
	(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt		$	65.6	$	179.9
Current maturities of long-term debt			100.0		128.0
Accounts payable and accrued liabilities			238.4		201.7
Accounts payable to associated companies			68.0		75.8
Capital lease obligations due within one year			6.2		6.0
Taxes accrued			85.8		90.1
Interest accrued			17.3		17.0
Liabilities and accrued interest related to uncertain tax positions			37.8		67.8
Other			110.1		88.9
Total Current Liabilities			729.2		855.2
DEFERRED CREDITS
Regulatory liabilities			548.0		542.4
Deferred income taxes, net			650.4		619.2
Investment tax credits			11.5		12.5
Other postretirement benefit obligation			57.1		57.4
Income taxes payable			133.2		129.0
Other			68.1		70.1
Total Deferred Credits			1,468.3		1,430.6
LONG-TERM LIABILITIES
Long-term debt			1,194.7		1,111.7
Capital lease obligations			102.1		105.2
Total Long-Term Liabilities			1,296.8		1,216.9
COMMITMENTS AND CONTINGENCIES  (NOTE 10)
SHAREHOLDER’S EQUITY
Common stock, $.01 par value, authorized     200,000,000 shares, issued 100 shares			-		-
Premium on stock and other capital contributions			611.4		533.4
Retained earnings			623.5		596.9
Total Shareholder’s Equity			1,234.9		1,130.3
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY		$	4,729.2	$	4,633.0

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

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POTOMAC ELECTRIC POWER COMPANY STATEMENTS OF CASH FLOWS (Unaudited)
		Six Months Ended June 30,
			2008		2007
	(Millions of dollars)
OPERATING ACTIVITIES
Net income		$	46.6	$	26.7
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization			69.2		83.9
Deferred income taxes			37.1		(5.9)
Gain on sale of assets			-		(.6)
Changes in:
Accounts receivable			(21.5)		(29.8)
Regulatory assets and liabilities			(33.1)		(34.3)
Accounts payable and accrued liabilities			52.5		53.5
Interest and taxes accrued			(15.3)		1.6
Other changes in working capital			5.7		(3.9)
Net other operating			4.3		6.4
Net Cash From Operating Activities			145.5		97.6
INVESTING ACTIVITIES
Net investment in property, plant and equipment			(120.9)		(134.0)
Changes in restricted cash			(17.0)		-
Net other investing activities			-		.1
Net Cash Used By Investing Activities			(137.9)		(133.9)
FINANCING ACTIVITIES
Dividends paid to Pepco Holdings			(20.0)		(29.0)
Capital contribution from Pepco Holdings			78.0		-
Issuances of long-term debt			250.0		-
Reacquisition of long-term debt			(187.5)		(35.0)
(Repayments) issuances of short-term debt, net			(114.3)		104.5
Net other financing activities			(16.6)		(5.6)
Net Cash (Used By) From Financing Activities			(10.4)		34.9
Net Decrease in Cash and Cash Equivalents			(2.8)		(1.4)
Cash and Cash Equivalents at Beginning of Period			19.0		12.4
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	16.2	$	11.0
NONCASH ACTIVITIES
Asset retirement obligations associated with removal   costs transferred to regulatory liabilities		$	5.2	$	3.1
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for income taxes    (includes payments to PHI for Federal income taxes)		$	2.2	$	23.2

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

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NOTES TO FINANCIAL STATEMENTS

POTOMAC ELECTRIC POWER COMPANY

(1)  ORGANIZATION

Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in Washington, D.C. and major portions of Prince George’s and Montgomery Counties in suburban Maryland.  Pepco provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier, in both the District of Columbia and Maryland.  Default Electricity Supply is known as Standard Offer Service in both the District of Columbia and Maryland.  Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (Pepco Holdings or PHI).

(2)  SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

Pepco’s unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP).  Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted.  Therefore, these financial statements should be read along with the annual financial statements included in Pepco’s Annual Report on Form 10-K for the year ended December 31, 2007.  In the opinion of Pepco’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly Pepco’s financial condition as of June 30, 2008, in accordance with GAAP.  The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.  Interim results for the three and six months ended June 30, 2008 may not be indicative of results that will be realized for the full year ending December 31, 2008 since the sales of electric energy are seasonal.

FIN 46R, “Consolidation of Variable Interest Entities”

Due to a variable element in the pricing structure of Pepco’s purchase power agreement with Panda-Brandywine, L.P. (Panda) entered into in 1991, pursuant to which Pepco is obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (Panda PPA), Pepco potentially assumes the variability in the operations of the plants related to the Panda PPA and therefore has a variable interest in the entity.  In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R (revised December 2003), entitled “Consolidation of Variable Interest Entities” (FIN 46R) and FASB Staff Position (FSP) 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)” (FSP FIN 46(R)-6), Pepco continued, during the second quarter of 2008, to conduct exhaustive efforts to obtain information from this entity, but was unable to obtain sufficient information to conduct the analysis required under FIN 46R to determine whether the entity was a variable interest entity or if Pepco was the primary beneficiary.  As a result, Pepco has applied the scope exemption from the application of FIN 46R for enterprises

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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 June 30, 2008 and 2007 were approximately $22 million and $20 million, respectively.  Power purchases related to the Panda PPA for the six months ended June 30, 2008 and 2007 were approximately $42 million and $43 million, respectively.  There is no loss exposure under the Panda PPA because recovery will be achieved through the sale of purchased power into PJM Interconnection, LLC (PJM), and with the funds received from the Mirant Corporation (Mirant) bankruptcy settlement covering the amount by which the purchase cost exceeds the proceeds from the sale.  On June 20, 2008, Pepco entered into an agreement to sell the Panda PPA to Sempra Energy Trading LLP in a transaction that is expected to close later this year. See Note 10 “Commitments and Contingencies — Regulatory and Other Matters — Proceeds from Settlement of Mirant Bankruptcy Claims.”

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $58.3 million and $60.5 million for the three months ended June 30, 2008 and 2007, respectively, and $115.3 million and $116.6 million for the six months ended June 30, 2008 and 2007, respectively.

Reclassifications and Adjustments

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

In the second quarter of 2008, Pepco recorded an adjustment to correct errors in other operation and maintenance expenses for prior periods where late payment fees were incorrectly recognized.  This adjustment resulted in an increase in other operation and maintenance expenses for the three and six months ended June 30, 2008 of $3.7 million and $3.3 million, respectively.  These adjustments are not considered material.

(3)  NEWLY ADOPTED ACCOUNTING STANDARDS

SFAS No. 157, "Fair Value Measurements"

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

SFAS No. 157 nullified a portion of Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,”(EITF 02-3). Under EITF 02-3, the transaction price presumption prohibited recognition of a trading profit at inception of a derivative unless the positive fair value of that derivative was substantially based on quoted prices or a valuation process incorporating observable inputs.  For transactions that did not meet this criterion at inception, trading profits that had been deferred were recognized in the period that inputs to value the derivative became observable or when the contract was performed.

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SFAS No. 157 nullified this portion of EITF 02-3.  SFAS No. 157 also: (1) establishes that fair value is based on a hierarchy of inputs into the valuation process (as described in Note 9), (2) clarifies that an issuer's credit standing should be considered when measuring liabilities at fair value, (3) precludes the use of a liquidity or blockage factor discount when measuring instruments traded in an actively quoted market at fair value and (4) requires costs relating to acquiring instruments carried at fair value to be recognized as expense when incurred.  SFAS No. 157 requires that a fair value measurement reflect the assumptions market participants would use in pricing an asset or liability based on the best available information.  These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model.

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

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

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

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

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

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

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

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

(4)  RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

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

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

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

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

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

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

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

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

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

FSP FAS 142-3, “Determination of the Useful Life of Intangible Assets”

On April 25, 2008, the FASB issued FSP Financial Accounting Standards (FAS) 142-3, “Determination of the Useful Life of Intangible Assets,” (FSP FAS 142-3) which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142).  The intent of FSP FAS 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the

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period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combinations,” and other U.S. generally accepted accounting principles (GAAP).

In developing assumptions about renewal or extension used to determine the useful life of a recognized intangible asset, an entity should consider its own historical experience in renewing or extending similar arrangements; however, these assumptions should be adjusted for entity-specific factors as discussed in SFAS No. 142.  In the absence of that experience, an entity should consider the assumptions that market participants would use about renewal or extension (consistent with the highest and best use of the asset by market participants), adjusted for the entity-specific factors as discussed in SFAS No. 142.

FSP FAS 142-3 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for Pepco).  Early adoption is prohibited.  The guidance for determining the useful life of a recognized intangible asset in FSP FAS 142-3 shall be applied prospectively to intangible assets acquired after the effective date.  The disclosure requirements shall be applied prospectively to all intangible assets recognizedas of, and subsequent to, the effective date.  Pepco is currently evaluating the impact FSP FAS 142-3 may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

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

On May 9, 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162) which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP in the United States (the GAAP hierarchy).  Moving the GAAP hierarchy into the accounting literature appropriately directs the hierarchy to the reporting entity responsible for the content of the financial statements, rather than to the auditors.

SFAS No. 162 is effective sixty days following the Securities and Exchange Commission’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of ‘Present fairly in conformity with generally accepted accounting principles’.”  The application of SFAS No. 162 is not expected to result in a change in accounting; however, if it does, the accounting change must be reported as a change in accounting principle under SFAS No. 154, “Accounting Changes and Error Corrections.”  Pepco is currently evaluating the impact SFAS No. 162 may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

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

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

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

FSP APB 14-1 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for Pepco).  FSP APB 14-1 shall be applied retrospectively to all periods presented.  Early adoption is not permitted.  Pepco does not currently have any convertible debt instruments outstanding; however, these types of instruments may be considered for financing future endeavors.

(5)  SEGMENT INFORMATION

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

(6)  PENSIONS AND OTHER POSTRETIREMENT BENEFITS

Pepco accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan.  PHI’s pension and other postretirement net periodic benefit cost for the three months ended June 30, 2008, of $16.2 million includes $5.8 million for Pepco’s allocated share.  PHI's pension and other postretirement net periodic benefit cost for the six months ended June 30, 2008, of $32.2 million includes $12.1 million for Pepco's allocated share.

PHI’s pension and other postretirement net periodic benefit cost for the three months ended June 30, 2007, of $10.8 million includes $3.2 million for Pepco’s allocated share.  PHI's pension and other postretirement net periodic benefit cost for the six months ended June 30, 2007, of $27.8 million includes $11.2 million for Pepco's allocated share.

(7)  DEBT

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

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

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

·   In April 2008, Pepco purchased $109.5 million of Pollution Control Revenue Refunding Bonds Series 2006 due 2022 issued by the Maryland Economic Development Corporation for the benefit of Pepco.  These purchases of insured tax-exempt auction rate bonds were made in response to disruption in the market

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for municipal auction rate securities that made it difficult for the remarketing agent to successfully remarket the bonds.  These bonds are considered to be extinguished for accounting purposes; however Pepco intends to hold the bonds, while monitoring the market and evaluating the options for remarketing the bonds to the public at some time in the future.

(8)  INCOME TAXES

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2008		2007		2008		2007
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
Depreciation	2.9		4.9		3.8		6.6
Asset removal costs	(1.3)		(1.6)		(3.1)		(2.4)
State income taxes, net of federal effect	5.5		6.2		6.1		6.2
Software amortization	1.1		2.3		1.5		3.3
Tax credits	(1.1)		(1.6)		(1.4)		(2.2)
Change in estimates and interest related to uncertain         and effectively settled tax positions	(6.1)		(.7)		(4.9)		(2.2)
Permanent differences related to deferred         compensation funding	-		-		.8		-
State interest refund	(5.0)		-		(3.2)		-
Other, net	.1		(3.1)		(.2)		(3.4)
Effective Income Tax Rate	31.1	%	41.4	%	34.4	%	40.9	%

Pepco’s effective tax rates for the three months ended June 30, 2008 and 2007 were 31.1% and 41.4%, respectively.  The change in the rate primarily resulted from the June 2008 receipt of interest of $3.5 million ($2.2 million after-tax) on the Company’s state tax refund received in the third quarter of 2007, certain depreciation book/tax differences, and a reduction in previously accrued interest in the second quarter of 2008 related to the uncertain tax positions for the tentative IRS settlement on the mixed service cost issue (as further discussed in Note 10).  These benefits were offset by the recording of certain interest adjustments related to prior period uncertain tax positions as discussed below.

Pepco’s effective tax rates for the six months ended June 30, 2008 and 2007 were 34.4% and 40.9%, respectively.  The change in the rate primarily resulted from the June 2008 receipt of interest of $3.5 million ($2.2 million after-tax) on the Company’s state tax refund received in the third quarter of 2007, certain depreciation book/tax differences, and a reduction in previously accrued interest in the second quarter of 2008 related to the uncertain tax positions for the tentative IRS settlement on the mixed service cost issue (as further discussed in Note 10).  These benefits were offset by the recording of certain interest adjustments related to prior period uncertain tax positions as discussed below.

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

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reduction in its liability for unrecognized tax benefits of $15.8 million and recognized after-tax interest income of $2.7 million.

In the second quarter of 2008, Pepco recorded certain adjustments to correct errors in the prior period FIN 48 interest calculations.  These interest adjustments resulted in additional income tax expense for the three and six months ended June 30, 2008 of $1.2 million and $.8 million, respectively, and are not considered material.

(9)  FAIR VALUE DISCLOSURES

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

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

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

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

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

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

The following table sets forth by level within the fair value hierarchy Pepco's financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2008.  As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Pepco's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at Reporting Date Using
	(Millions of dollars)
Description	June 30, 2008	Quoted Prices in Active Markets for Identical Instruments (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
ASSETS
Executive deferred   compensation plan assets	$61.1	$      -	$43.9	$17.2
	$61.1	$      -	$43.9	$17.2
LIABILITIES
Executive deferred   compensation plan liabilities	$15.0	$      -	$15.0	$     -
	$15.0	$      -	$15.0	$     -

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

	Deferred Compensation Plan Assets
Beginning balance as of January 1, 2008	$16.0
Total gains or (losses) (realized/unrealized)
Included in earnings	1.8
Included in other comprehensive income	-
Purchases and issuances	-
Settlements	(.6)
Transfers in and/or out of Level 3	-
Ending balance as of June 30, 2008	$17.2
Gains or (losses) (realized and unrealized) included in earnings for the period above are reported in Other Operation and Maintenance Expense as follows:	Other Operation and Maintenance Expense
Total gains included in earnings for the period above	$  1.8
Change in unrealized gains relating to assets still held at reporting date	$  1.8

(10)  COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Proceeds from Settlement of Mirant Bankruptcy Claims

In 2000, Pepco sold substantially all of its electricity generating assets to Mirant and certain of its subsidiaries.  In 2003, Mirant commenced a voluntary bankruptcy proceeding in which it sought to reject certain obligations that it had undertaken in connection with the asset sale.  As part of the sale, Pepco and Mirant entered into a “back-to-back” arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco is obligated to purchase annually through 2021 from Panda under the Panda PPA at the purchase price Pepco is obligated to pay to Panda.  In connection with the settlement of Pepco’s claims against Mirant arising from the Mirant bankruptcy, Pepco agreed not to contest the rejection by Mirant of its obligations under the “back-to-back” arrangement in exchange for the payment by Mirant of damages corresponding to the estimated amount by which the purchase price that Pepco is obligated to pay Panda for the energy and capacity exceeded the market price.  In 2007, Pepco received as damages $413.9 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant.  These funds are being accounted for as restricted cash based on management’s intent to use such funds, and any interest earned thereon, for the sole purpose of paying for the future above-market capacity and energy purchase costs under the Panda PPA.  Correspondingly, a regulatory liability has been established in the same amount to help offset the future above-market capacity and energy purchase costs.  This restricted cash has been classified as a non-current asset to be consistent with the classification of the non-current regulatory liability, and any changes in the balance of this restricted cash, including interest on the invested funds, are being accounted for as operating cash flows.  As of June 30, 2008, the balance of the restricted cash account was approximately $412 million.

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On June 20, 2008, Pepco entered into an agreement with Panda and Sempra Energy Trading LLC (Sempra) under which Pepco has agreed, in exchange for a payment from Pepco to Sempra, to transfer the Panda PPA to Sempra (the Transfer Agreement).  Upon closing of the transaction, Pepco will have no further rights and obligations under the Panda PPA.  The closing of the transaction is subject to various conditions.  In the event the closing does not occur on or before September 22, 2008, any party to the Transfer Agreement has the right to terminate the transaction.

In view of the entry into the Transfer Agreement, Pepco has withdrawn previous applications filed with the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC) requesting orders directing it to place $320 million of the damages received from Mirant in a special purpose account to be used solely for paying the future above-market cost of the Panda PPA.  Following the transfer of the Panda PPA, Pepco intends to file revised rates with the DCPSC and the MPSC for the purpose of distributing the remaining funds in the restricted cash account after deducting the payment made to Sempra under the Transfer Agreement.  The portion of the balance of the funds in the restricted cash account that Pepco ultimately retains will depend on the customer sharing arrangements approved by the DCPSC and the MPSC.

Rate Proceedings

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

District of Columbia

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

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Maryland

In July 2007, the MPSC issued an order in the electric service distribution rate case filed Pepco, which included approval of a BSA.  The order approved an annual increase in distribution rates of approximately $10.6 million (including a decrease in annual depreciation expense of approximately $30.7 million).  The approved distribution rate reflects an ROE of 10.0%.  The rate increases were effective as of June 16, 2007, and remained in effect for an initial period until July 19, 2008, pending a Phase II proceeding in which the MPSC considered the results of an audit of Pepco’s cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates was required.  On July 18, 2008, the MPSC issued an order in the Phase II proceeding, denying any further adjustment to the Pepco rates, thus making permanent the rate increases approved in the July 2007 orders.

Divestiture Cases

District of Columbia

In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets.  An unresolved issue relating to the application filed with the DCPSC by Pepco to implement the divestiture settlement is whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code and its implementing regulations.  As of June 30, 2008, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6.5 million and $5.8 million, respectively.  Other issues in the divestiture proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.

Pepco believes that a sharing of EDIT and ADITC would violate the IRS normalization rules.  Under these rules, Pepco could not transfer the EDIT and the ADITC benefit to customers more quickly than on a straight line basis over the book life of the related assets. Since the assets are no longer owned by Pepco, there is no book life over which the EDIT and ADITC can be returned.  If Pepco were required to share EDIT and ADITC and, as a result, the normalization rules were violated, Pepco would be unable to use accelerated depreciation on District of Columbia allocated or assigned property.  In addition to sharing with customers the generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS an amount equal to Pepco’s District of Columbia jurisdictional generation-related ADITC balance ($5.8 million as of June 30, 2008), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3.7 million as of June 30, 2008) in each case as those balances exist as of the later of the date a DCPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the DCPSC order becomes operative.

On March 6, 2008, the IRS approved final regulations, effective March 20, 2008, which allow utilities whose assets cease to be utility property (whether by disposition, deregulation or otherwise) to return to its utility customers the normalization reserve for EDIT and part or all of the normalization reserve for ADITC.  This ruling applies to assets divested after December 21, 2005.  For utility property divested on or before December 21, 2005, the IRS stated that it would

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continue to follow the holdings set forth in private letter rulings prohibiting the flow through of EDIT and ADITC associated with the divested assets.  Pepco made a filing on April 22, 2008, advising the DCPSC of the adoption of the final regulations and requesting that the DCPSC issue an order consistent with the IRS position.  If the DCPSC issues the requested order, no accounting adjustments to the gain recorded in 2000 would be required.

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

Maryland

Pepco filed its divestiture proceeds plan application with the MPSC in April 2001.  The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that has been raised in the District of Columbia case.  See the discussion above under “Divestiture Cases — District of Columbia.”  As of June 30, 2008, the Maryland allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $9.1 million and $10.4 million, respectively.  Other issues deal with the treatment of certain costs as deductions from the gross proceeds of the divestiture.  In November 2003, the Hearing Examiner in the Maryland proceeding issued a proposed order with respect to the application that concluded that Pepco’s Maryland divestiture settlement agreement provided for a sharing between Pepco and customers of the EDIT and ADITC associated with the sold assets.  Pepco believes that such a sharing would violate the normalization rules (as discussed above) and would result in Pepco’s inability to use accelerated depreciation on Maryland allocated or assigned property.  If the proposed order is affirmed, Pepco would have to share with its Maryland customers, on an approximately 50/50 basis, the Maryland allocated portion of the generation-related EDIT ($9.1 million as of June 30, 2008), and the Maryland-allocated portion of generation-related ADITC.  Furthermore, Pepco would have to pay to the IRS an amount equal to Pepco’s Maryland jurisdictional generation-related ADITC balance ($10.4 million as of June 30, 2008), as well as its Maryland retail jurisdictional ADITC transmission and distribution-related balance ($6.6 million as of June 30, 2008), in each case as those balances exist as of the later of the date a MPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the MPSC order becomes operative.  The Hearing Examiner decided all other issues in favor of Pepco, except for the determination that only one-half of the severance payments that Pepco included in its calculation of corporate reorganization costs should be deducted from the sales proceeds before sharing of the net gain between Pepco and customers.

In December 2003, Pepco appealed the Hearing Examiner’s decision to the MPSC as it relates to the treatment of EDIT and ADITC and corporate reorganization costs.  The MPSC has not issued any ruling on the appeal, pending completion of the IRS rulemaking regarding sharing of EDIT and ADITC related to divested assets.  Pepco made a filing on April 22, 2008, advising the MPSC of the adoption of the final IRS normalization regulations (described above under

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“Divestiture Cases -- District of Columbia”) and requesting that the MPSC issue a ruling on the appeal consistent with the IRS position.  If the MPSC issues the requested ruling, no accounting adjustments to the gain recorded in 2000 would be required.  However, neither PHI nor Pepco believes that additional gain-sharing payments, if any, or the ADITC-related payments to the IRS, if required, would have a material adverse impact on its financial position or cash flows.

General Litigation

During 1993, Pepco was served with Amended Complaints filed in the state Circuit Courts of Prince George’s County, Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated proceedings known as “In re: Personal Injury Asbestos Case.”  Pepco and other corporate entities were brought into these cases on a theory of premises liability.  Under this theory, the plaintiffs argued that Pepco was negligent in not providing a safe work 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 June 30, 2008, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement between Pepco and Mirant under which Pepco sold its generation assets to Mirant in 2000.

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

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,

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environmental clean-up costs incurred by Pepco would be included in its cost of service for ratemaking purposes.

Carolina Transformer Site.  In August 2006, the U.S. Environmental Protection Agency (EPA) notified Pepco that it had been identified as an entity that sent PCB-laden oil to be disposed at the Carolina Transformer site in Fayetteville, North Carolina.  The EPA notification stated that, on this basis, Pepco may be a potentially responsible party (PRP).  In early 2008, EPA, the PRP group and the State of North Carolina entered into a settlement agreement under which (i) Pepco paid $162,000 to resolve any liability that it might have at the site to EPA and the State of North Carolina, (ii) EPA and the State of North Carolina covenanted not to sue or bring administrative action against Pepco for response costs at the site, (iii) other PRP group members released all rights for cost recovery or contribution claims they may have against Pepco, and (iv) Pepco released all rights for cost recovery or contribution claims that it may have against other parties settling with EPA and the State of North Carolina.  The consent decree related to the settlement agreement was lodged with the U.S. District Court for the Eastern District of North Carolina on June 6, 2008.  No comments were filed during the public notice and comment period, which expired on July 16, 2008, and on July 30, 2008, EPA and the State of North Carolina filed their motion requesting the court to enter the consent decree.

IRS Mixed Service Cost Issue

During 2001, Pepco changed its method of accounting with respect to capitalizable construction costs for income tax purposes.  The change allowed Pepco to accelerate the deduction of certain expenses that were previously capitalized and depreciated.  Through December 31, 2005, these accelerated deductions generated incremental tax cash flow benefits of approximately $94 million, primarily attributable to its 2001 tax returns.

In 2005, the Treasury Department issued proposed regulations that, if adopted in their current form, would require Pepco to change its method of accounting with respect to capitalizable construction costs for income tax purposes for tax periods beginning in 2005.  Based on the proposed regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believed would be acceptable to the IRS.

At the same time as the proposed regulations were released, the IRS issued Revenue Ruling 2005-53, which was intended to limit the ability of certain taxpayers to utilize the method of accounting for income tax purposes they utilized on their tax returns for 2004 and prior years with respect to capitalizable construction costs.  In line with this Revenue Ruling, the IRS revenue agent’s report for the 2001 and 2002 tax returns disallowed substantially all of the incremental tax benefits that Pepco had claimed on those returns by requiring it to capitalize and depreciate certain expenses rather than treat such expenses as current deductions.  PHI’s protest of the IRS adjustments is included in the audit matters relating to the 2001 and 2002 audits pending before the U.S. Office of Appeals of the IRS (Appeals Office).

In February 2006, PHI paid approximately $121 million of taxes (a portion of which is attributable to Pepco) to cover the amount of additional taxes and interest that management estimated to be payable for the years 2001 through 2004 based on the method of tax accounting that PHI, pursuant to the proposed regulations, adopted on its 2005 tax return.  In June 2008, PHI received from the Appeals Office an offer of settlement pertaining to Pepco for the tax years

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2001 through 2004.  Pepco is substantially in agreement with this proposed settlement.  Based on the terms of the proposal, Pepco expects the final settlement amount to be less than the amount previously deposited.  Accordingly, in the quarter ended June 30, 2008, Pepco recorded after-tax interest income of $2.7million and a net reduction in its liability for unrecognized tax benefits of $15.8 million.

(11)  RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including Pepco.  The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods.  PHI Service Company costs directly charged or allocated to Pepco for the three months ended June 30, 2008 and 2007 were approximately $34.4 million and $30.3 million, respectively.  PHI Service Company costs directly charged or allocated to Pepco for the six months ended June 30, 2008 and 2007 were approximately $69.8 million and $61.5 million, respectively.

Certain subsidiaries of Pepco Energy Services perform utility maintenance services, including services that are treated as capital costs, for Pepco.  Amounts charged to Pepco by these companies for the three months ended June 30, 2008 and 2007 were approximately $2.6 million and $7.6 million, respectively.  Amounts charged to Pepco by these companies for the six months ended June 30, 2008 and 2007 were approximately $5.3 million and $16.0 million, respectively.

In addition to the transactions described above, Pepco’s financial statements include the following related party transactions in its Statements of Earnings:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2008		2007		2008		2007
	(Millions of dollars)
Income (Expense)
Intercompany power purchases -     Conectiv Energy Supply (a)	$	(8.0)	$	(13.8)	$	(22.6)	$	(29.6)	(
Intercompany lease transactions (b)	$	-	$	(.2)	$	(.1)	$	(.4)

(a) Included in fuel and purchased energy.

(b) Included in other operation and maintenance.

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

	June 30, 2008	December 31, 2007
Asset (Liability)	(Millions of dollars)
Payable to Related Party (current)
PHI Service Company	$(18.3)	$(16.9)
Conectiv Energy Supply	(.3)	(5.8)
Pepco Energy Services (a)	(48.8)	(53.0)
The items listed above are included in the “Accounts payable to associated companies” balance on the Balance Sheet of $68.0 million and $75.8 million at June 30, 2008 and December 31, 2007, respectively.
Money Pool Balance with Pepco Holdings (included in short-term debt)	$(15.6)	$(95.9)
Money Pool Interest Accrued (included in interest accrued)	-	(.3)

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

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DELMARVA POWER & LIGHT COMPANY STATEMENTS OF EARNINGS (Unaudited)
	Three Months Ended June 30,				Six Months Ended June 30,
		2008		2007		2008		2007
		(Millions of dollars)
Operating Revenue
Electric	$	288.6	$	265.0	$	583.4	$	573.7
Natural Gas		83.0		65.1		198.7		177.9
Total Operating Revenue		371.6		330.1		782.1		751.6
Operating Expenses
Fuel and purchased energy		191.3		182.5		386.7		403.3
Gas purchased		68.8		51.0		156.5		137.1
Other operation and maintenance		54.3		49.8		110.3		99.4
Depreciation and amortization		18.0		18.2		36.1		37.3
Other taxes		7.9		8.5		17.5		17.8
Gain on sale of assets		-		-		(3.1)		(.6)
Total Operating Expenses		340.3		310.0		704.0		694.3
Operating Income		31.3		20.1		78.1		57.3
Other Income (Expenses)
Interest and dividend income		.5		.1		1.6		.7
Interest expense		(8.7)		(10.4)		(18.2)		(21.4)
Other income		.7		.6		1.4		1.1
Other expense		-		-		-		-
Total Other Expenses		(7.5)		(9.7)		(15.2)		(19.6)
Income Before Income Tax Expense		23.8		10.4		62.9		37.7
Income Tax Expense		7.5		1.8		20.5		13.1
Net Income		16.3		8.6		42.4		24.6
Retained Earnings at Beginning of Period		430.9		433.9		431.8		426.4
Dividends Paid to Parent		(15.0)		(19.0)		(42.0)		(27.0)
Preferred Stock Redemption		-		-		-		(.6)
Cumulative Effect Adjustment Related   to the Implementation of FIN 48		-		-		-		.1
Retained Earnings at End of Period	$	432.2	$	423.5	$	432.2	$	423.5

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

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DELMARVA POWER & LIGHT COMPANY BALANCE SHEETS (Unaudited)
ASSETS		June 30, 2008		December 31, 2007
	(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$	7.3	$	11.4
Restricted cash			36.1		3.8
Accounts receivable, less allowance for uncollectible accounts     of $10.6 million and $8.0 million, respectively			213.7		194.9
Fuel, materials and supplies - at average cost			40.3		45.3
Prepayments of income taxes			50.4		56.1
Prepaid expenses and other			23.6		15.2
Total Current Assets			371.4		326.7
INVESTMENTS AND OTHER ASSETS
Goodwill			8.0		8.0
Regulatory assets			196.7		224.6
Prepaid pension expense			181.1		178.1
Other			38.3		35.3
Total Investments and Other Assets			424.1		446.0
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			2,595.3		2,615.8
Accumulated depreciation			(815.3)		(828.8)
Net Property, Plant and Equipment			1,780.0		1,787.0
TOTAL ASSETS		$	2,575.5	$	2,559.7

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

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DELMARVA POWER & LIGHT COMPANY BALANCE SHEETS (Unaudited)
LIABILITIES AND SHAREHOLDER’S EQUITY		June 30, 2008		December 31, 2007
	(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt		$	138.9	$	286.2
Current maturities of long-term debt			18.2		22.6
Accounts payable and accrued liabilities			128.9		104.7
Accounts payable to associated companies			48.5		54.0
Taxes accrued			6.9		8.2
Interest accrued			6.1		5.7
Liabilities and accrued interest related to uncertain tax positions			13.3		34.1
Other			77.1		60.5
Total Current Liabilities			437.9		576.0
DEFERRED CREDITS
Regulatory liabilities			292.1		275.5
Deferred income taxes, net			441.7		410.1
Investment tax credits			8.6		9.0
Above-market purchased energy contracts and other      electric restructuring liabilities			20.1		21.1
Other			53.0		65.2
Total Deferred Credits			815.5		780.9
LONG-TERM LIABILITIES
Long-term debt			586.0		529.4
COMMITMENTS AND CONTINGENCIES (NOTE 10)
SHAREHOLDER’S EQUITY
Common stock, $2.25 par value, authorized     1,000 shares, issued 1,000 shares			-		-
Premium on stock and other capital contributions			303.9		241.6
Retained earnings			432.2		431.8
Total Shareholder’s Equity			736.1		673.4
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY		$	2,575.5	$	2,559.7

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

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DELMARVA POWER & LIGHT COMPANY STATEMENTS OF CASH FLOWS (Unaudited)
	Six Months Ended June 30,
		2008		2007
	(Millions of dollars)
OPERATING ACTIVITIES
Net income	$	42.4	$	24.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		36.1		37.3
Gain on sale of assets		(3.1)		(.6)
Investment tax credit adjustments		(.4)		(.4)
Deferred income taxes		30.6		6.8
Changes in:
Accounts receivable		(18.2)		(1.9)
Regulatory assets and liabilities		20.8		.6
Accounts payable and accrued liabilities		31.5		37.6
Interest and taxes accrued		(20.7)		.2
Other changes in working capital		4.9		(10.1)
Net other operating		4.4		(3.9)
Net Cash From Operating Activities		128.3		90.2
INVESTING ACTIVITIES
Net investment in property, plant and equipment		(71.9)		(59.5)
Restricted cash		(32.3)		(2.9)
Proceeds from sale of assets		50.1		-
Net other investing activities		(.1)		.1
Net Cash Used By Investing Activities		(54.2)		(62.3)
FINANCING ACTIVITIES
Dividends paid to Parent		(42.0)		(27.0)
Capital contribution from Parent		62.3		-
Issuance of long-term debt		150.0		-
Reacquisition of long-term debt		(97.8)		(64.7)
(Repayments)/issuances of short-term debt, net		(147.3)		78.9
Redemption of preferred stock		-		(18.2)
Net other financing activities		(3.4)		(.8)
Net Cash Used By Financing Activities		(78.2)		(31.8)
Net Decrease in Cash and Cash Equivalents		(4.1)		(3.9)
Cash and Cash Equivalents at Beginning of Period		11.4		8.2
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	7.3	$	4.3
NONCASH ACTIVITIES
Asset retirement obligations associated with removal costs   transferred to regulatory liabilities	$	(3.3)	$	4.2
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for income taxes    (includes payments to PHI for Federal income taxes)	$	10.6	$	11.9

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

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NOTES TO FINANCIAL STATEMENTS

DELMARVA POWER & LIGHT COMPANY

(1)  ORGANIZATION

Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and Virginia (until the sale of its Virginia operations on January 2, 2008), and provides gas distribution service in northern Delaware.  Additionally, DPL supplies electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier.  The regulatory term for this service varies by jurisdiction as follows:

Delaware	Standard Offer Service (SOS)
Maryland	SOS
Virginia	Default Service (prior to January 2, 2008)

In this Form 10-Q, DPL also refers to these supply services generally as Default Electricity Supply.  DPL is a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).

In January 2008, DPL completed (i) the sale of its retail electric distribution business on the Eastern Shore of Virginia to A&N Electric Cooperative (A&N) for a purchase price of approximately $48.8 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission business located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase price of approximately $5.4 million, after closing adjustments.  Each of A&N and ODEC assumed certain post-closing liabilities and unknown pre-closing liabilities related to the respective assets they purchased (including, in the A&N transaction, most environmental liabilities), except that DPL remained liable for unknown pre-closing liabilities if they become known within six months after the January 2, 2008 closing date.  The allowance period for A&N and/or ODEC to notify DPL has passed and no notification was made with respect to the discovery of additional pre-closing liabilities.  A&N has delayed final payment of approximately $3.5 million due to a dispute in the final true-up amounts.  DPL is in discussions with A&N to resolve the issues.  DPL can not predict the outcome of these discussions.  These sales resulted in a $3.1 million pre-tax gain ($1.8 million after-tax), which was recorded during the first quarter of 2008.  In connection with the sales, A&N assumed on the sale date DPL’s obligation to provide Default Supply to customers in DPL’s former Virginia service territory.

(2)  SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

DPL’s unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP).  Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP

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have been omitted.  Therefore, these financial statements should be read along with the annual financial statements included in DPL’s Annual Report on Form 10-K for the year ended December 31, 2007.  In the opinion of DPL’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly DPL’s financial condition as of June 30, 2008, in accordance with GAAP.  The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.  Interim results for the three and six months ended June 30, 2008 may not be indicative of results that will be realized for the full year ending December 31, 2008 since the sales of electric energy are seasonal.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $3.6 million and $3.0 million for the three months ended June 30, 2008 and 2007, respectively, and $7.1 million and $6.2 million for the six months ended June 30, 2008 and 2007, respectively.

Reclassifications

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

(3)  NEWLY ADOPTED ACCOUNTING STANDARDS

SFAS No. 157, "Fair Value Measurements"

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

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

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

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

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

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

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

SFAS No. 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities.  SFAS No. 159 requires companies to provide additional information that

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will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings.  It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet.  SFAS No. 159 does not eliminate disclosure requirements included in other accounting standards.

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

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

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

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

(4)  RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

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

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

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

This Statement amends FASB Statement No. 109, “Accounting for Income Taxes” to require the acquirer to recognize changes in the amount of its deferred tax benefits that are recognizable because of a business combination either in income from continuing operations in

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the period of the combination or directly in contributed capital, depending on the circumstances (such changes arise through the increase or reduction of the acquirer’s valuation allowance on its previously existing deferred tax assets because of the business combination).  Previously, Statement 109 required a reduction of the acquirer’s valuation allowance because of a business combination to be recognized through a corresponding reduction to goodwill.

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

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

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

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

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

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

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

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

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

FSP FAS 142-3, “Determination of the Useful Life of Intangible Assets”

On April 25, 2008, the FASB issued FSP Financial Accounting Standards (FAS) 142-3, “Determination of the Useful Life of Intangible Assets,” (FSP FAS 142-3) which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142).  The intent of FSP FAS 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combinations,” and other U.S. generally accepted accounting principles (GAAP).

In developing assumptions about renewal or extension used to determine the useful life of a recognized intangible asset, an entity should consider its own historical experience in renewing or extending similar arrangements; however, these assumptions should be adjusted for entity-specific factors as discussed in SFAS No. 142.  In the absence of that experience, an entity should consider the assumptions that market participants would use about renewal or extension (consistent with the highest and best use of the asset by market participants), adjusted for the entity-specific factors as discussed in SFAS No. 142.

FSP FAS 142-3 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for DPL).  Early adoption is

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prohibited.  The guidance for determining the useful life of a recognized intangible asset in FSP FAS 142-3 shall be applied prospectively to intangible assets acquired after the effective date.  The disclosure requirements shall be applied prospectively to all intangible assets recognizedas of, and subsequent to, the effective date.  DPL is currently evaluating the impact FSP FAS 142-3 may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

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

On May 9, 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162) which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP in the United States (the GAAP hierarchy).  Moving the GAAP hierarchy into the accounting literature appropriately directs the hierarchy to the reporting entity responsible for the content of the financial statements, rather than to the auditors.

SFAS No. 162 is effective sixty days following the Securities and Exchange Commission’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of ‘Present fairly in conformity with generally accepted accounting principles’.”  The application of SFAS No. 162 is not expected to result in a change in accounting; however, if it does, the accounting change must be reported as a change in accounting principle under SFAS No. 154, “Accounting Changes and Error Corrections.”  DPL is currently evaluating the impact SFAS No. 162 may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

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

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

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

FSP APB 14-1 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for DPL).  FSP APB 14-1 shall be applied retrospectively to all periods presented.  Early adoption is not permitted.  DPL does not

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currently have any convertible debt instruments outstanding; however, these types of instruments may be considered for financing future endeavors.

(5)  SEGMENT INFORMATION

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

(6)  PENSION AND OTHER POSTRETIREMENT BENEFITS

DPL accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan.  PHI’s pension and other postretirement net periodic benefit cost for the three months ended June 30, 2008, of $16.2 million includes $.8 million for DPL’s allocated share.  PHI's pension and other postretirement net periodic benefit cost for the six months ended June 30, 2008, of $32.2 million includes $1.7 million for DPL's allocated share.

PHI’s pension and other postretirement net periodic benefit cost for the three months ended June 30, 2007, of $10.8 million includes $.9 million for DPL’s allocated share.  PHI's pension and other postretirement net periodic benefit cost for the six months ended June 30, 2007, of $27.8 million includes $1.2 million for DPL's allocated share.

(7)  DEBT

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

During the first quarter of 2008, DPL purchased at par $57.75 million in aggregate principal amount of insured tax-exempt auction rate bonds issued by municipal authorities for the benefit of DPL.  These purchases were made in response to disruption in the market for municipal auction rate securities that made it difficult for the remarketing agent to successfully remarket the bonds.  During the second quarter of 2008, DPL purchased at par additional insured tax-exempt auction rate bonds as follows:

·   In April 2008, DPL purchased the following series of bonds issued by the Delaware Economic Development Authority: (i) $20 million of Exempt Facilities Refunding Revenue Bonds 2001A Series due 2031, (ii) $4.5 million of Exempt Facilities Refunding Revenue Bonds 2001B Series due 2031, and (iii) $11.15 million of Exempt Facilities Refunding Revenue Bonds 2000A Series due 2030.

These bonds are considered to be extinguished for accounting purposes; however each of the companies intends to hold the bonds, while monitoring the market and evaluating the options for remarketing the bonds to the public at some time in the future.

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

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(8)  INCOME TAXES

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2008		2007		2008		2007
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect	5.5		5.7		5.4		5.0
Depreciation	2.5		6.6		1.9		3.2
Tax credits	(1.0)		(2.0)		(.6)		(1.0)
Change in estimates and interest related to uncertain         and effectively settled tax positions	(10.5)		(28.0)		(8.9)		(7.5)
Other, net	-		-		(.2)		-
Effective Income Tax Rate	31.5	%	17.3	%	32.6	%	34.7	%

DPL’s effective tax rates for the three months ended June 30, 2008 and 2007 were 31.5% and 17.3%, respectively.  The change in the rate resulted from a decrease in the benefit recognized on changes in estimates and interest related to uncertain and effectively settled tax positions (primarily related to the reversal of interest reserves related to a state tax position settled in 2007 partially offset by the reversal of interest reserves related to the Mixed Service Cost issue discussed below).

DPL’s effective tax rates for the six months ended June 30, 2008 and 2007 were 32.6% and 34.7%, respectively.  The change in the rate resulted from a decrease in the benefit recognized on changes in estimates and interest related to uncertain and effectively settled tax positions (primarily related to the reversal of interest reserves related to a state tax position settled in 2007 partially offset by the reversal of interest reserves related to the Mixed Service cost issue discussed below).

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

(9)  FAIR VALUE DISCLOSURES

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

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

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

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

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

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

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

The following table sets forth by level within the fair value hierarchy DPL's financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2008.  As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  DPL's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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	Fair Value Measurements at Reporting Date Using
	(Millions of dollars)
Description	June 30, 2008	Quoted Prices in Active Markets for Identical Instruments (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level  3)
ASSETS
Derivative Instruments	$14.8	$4.9	$2.6	$7.3
Executive deferred compensation plan assets	.8	-	-	.8
	$15.6	$4.9	$2.6	$8.1
LIABILITIES
Derivative Instruments	$ 2.0	$   -	$   -	$ 2.0
Executive deferred   compensation plan liabilities	.7	-	.7	-
	$ 2.7	$   -	$ .7	$ 2.0

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

	Net Derivative Instruments	Deferred Compensation Plan Assets
Beginning balance as of January 1, 2008	$(10.7)	$  .8
Total gains or (losses) (realized/unrealized)
Included in earnings	15.8	-
Included in other comprehensive income	-	-
Purchases and issuances	-	-
Settlements	.2	-
Transfers in and/or out of Level 3	-	-
Ending balance as of June 30, 2008	$  5.3	$  .8
Gains or (losses) (realized and unrealized) included in earnings for the period above are reported in Operating Revenue and Other Operation and Maintenance Expense as follows:	Operating Revenue	Other Operation and Maintenance Expense
Total gains included in earnings for the period above	$15.8	$   -
Change in unrealized gains relating to assets still held at reporting date	$14.4	$   -

(10)  COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

Rate Proceedings

In an 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

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BSA, customer delivery rates are subject to adjustment (through a surcharge or credit mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the approved revenue-per-customer amount.  The BSA will increase rates if actual distribution revenues fall below the level approved by the Maryland Public Service Commission (MPSC) and will decrease rates if actual distribution revenues are above the approved level.  The result will be that, over time, DPL would collect its authorized revenues for distribution deliveries.  As a consequence, a BSA “decouples” revenue from unit sales consumption and ties the growth in revenues to the growth in the number of customers.  Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable utility distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers’ delivery bills, and (iv) removes any disincentives for DPL to promote energy efficiency programs for its customers, because it breaks the link between overall sales volumes and delivery revenues.  The status of the BSA proposal is described below.

In July 2007, the MPSC issued an order in the electric service distribution rate case filed by DPL, which included approval of a BSA.  The order approved an annual increase in distribution rates of approximately $14.9 million (including a decrease in annual depreciation expense of approximately $.9 million).  The approved distribution rate reflects a return on equity of 10.0%.  The rate increases were effective as of June 16, 2007, and remained in effect for an initial period until July 19, 2008, pending a Phase II proceeding in which the MPSC considered the results of audits of DPL’s cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates was required.  On July 18, 2008, the MPSC issued an order in the Phase II proceeding, denying any further adjustment to DPL’s rates, thus making permanent the rate increases approved in the July 2007 orders.

DPL Sale of Virginia Operations

In January 2008, DPL completed (i) the sale of its retail electric distribution business on the Eastern Shore of Virginia to A&N for a purchase price of approximately $48.8 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission business located on the Eastern Shore of Virginia to ODEC for a purchase price of approximately $5.4 million, after closing adjustments.  Each of A&N and ODEC assumed certain post-closing liabilities and unknown pre-closing liabilities related to the respective assets they purchased (including, in the A&N transaction, most environmental liabilities), except that DPL remained liable for unknown pre-closing liabilities if they become known within six months after the January 2, 2008 closing date.  The allowance period for A&N and/or ODEC to notify DPL has passed and no notification was made with respect to the discovery of additional pre-closing liabilities.  A&N has delayed final payment of approximately $3.5 million, which was due on June 2, 2008, due to a dispute in the final true-up amounts.  DPL is in discussions with A&N to resolve the issues.  DPL can not predict the outcome of these discussions.

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

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may have been contaminated due to past disposal practices.  Although penalties assessed for violations of environmental laws and regulations are not recoverable from DPL’s customers, environmental clean-up costs incurred by DPL would be included in its cost of service for ratemaking purposes.

Carolina Transformer Site.  In August 2006, the U.S. Environmental Protection Agency (EPA) notified DPL that it had been identified as an entity that sent PCB-laden oil to be disposed at the Carolina Transformer site in Fayetteville, North Carolina.  The EPA notification stated that, on this basis, DPL may be a potentially responsible party (PRP).  In early 2008, EPA, the PRP group and the State of North Carolina entered into a settlement agreement under which (i)  DPL paid $162,000 to resolve any liability that it might have at the site to EPA and the State of North Carolina, (ii) EPA and the State of North Carolina covenanted not to sue or bring administrative action against DPL for response costs at the site, (iii) other PRP group members released all rights for cost recovery or contribution claims they may have against DPL, and (iv) DPL released all rights for cost recovery or contribution claims that they may have against other parties settling with EPA and the State of North Carolina.  The consent decree related to the settlement agreement was lodged with the U.S. District Court for the Eastern District of North Carolina on June 6, 2008.  No comments were filed during the public notice and comment period, which expired on July 16, 2008, and on July 30, 2008, EPA and the State of North Carolina filed their motion requesting the court to enter the consent decree.

IRS Mixed Service Cost Issue

During 2001, DPL changed its method of accounting with respect to capitalizable construction costs for income tax purposes.  The change allowed DPL to accelerate the deduction of certain expenses that were previously capitalized and depreciated.  Through December 31, 2005, these accelerated deductions generated incremental tax cash flow benefits of approximately $62 million, primarily attributable to its 2001 tax returns.

In 2005, the Treasury Department issued proposed regulations that, if adopted in their current form, would require DPL to change its method of accounting with respect to capitalizable construction costs for income tax purposes for tax periods beginning in 2005.  Based on the proposed regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believed would be acceptable to the IRS.

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

In February 2006, PHI paid approximately $121 million of taxes (a portion of which is attributable to DPL) to cover the amount of additional taxes and interest that management estimated to be payable for the years 2001 through 2004 based on the method of tax accounting that PHI, pursuant to the proposed regulations, adopted on its 2005 tax return.  In June 2008, PHI

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received from the Appeals Office an offer of settlement pertaining to DPL for the tax years 2001 through 2004.  DPL is substantially in agreement with this proposed settlement.  Based on the terms of the proposal, DPL expects the final settlement amount to be less than the amount previously deposited.  Accordingly, in the quarter ended June 30, 2008, DPL recorded after-tax interest income of $2.3million and a net reduction in its liability for unrecognized tax benefits of $.8 million.

(11)  RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including DPL.  The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods.  PHI Service Company costs directly charged or allocated to DPL for the three months ended June 30, 2008 and 2007 were $27.4 million and $26.5 million, respectively.  PHI Service Company costs directly charged or allocated to DPL for the six months ended June 30, 2008 and 2007 were approximately $54.9 million and $52.7 million, respectively.

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2008		2007		2008		2007
	(Millions of dollars)
Income (Expense)
SOS with Conectiv Energy Supply (a)	$	(42.7)	$	(59.2)	$	(104.1)	$	(135.5)	(
Intercompany lease transactions (b)		1.8		1.9		3.5		3.8
Transcompany pipeline gas purchases with     Conectiv Energy Supply (c)		(.9)		(.2)		(1.2)		(1.5)
Transcompany pipeline gas sales with     Conectiv Energy Supply (d)		.2		.1		.3		1.6

(a) Included in fuel and purchased energy.

(b) Included in electric revenue.

(c) Included in gas purchased.

(d) Included in gas revenue.

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

	June 30, 2008		December 31, 2007
Asset (Liability)		(Millions of dollars)
Payable to Related Party (current)
PHI Service Company	$	(17.5)	$	(24.7)
Conectiv Energy Supply		(26.6)		(23.0)
Pepco Energy Services		(4.7)		(6.6)
The items listed above are included in the “Accounts payable to associated companies” balance on the Balance Sheet of $48.5 million and $54.0 million at June 30, 2008 and December 31, 2007, respectively.
Money Pool Balance with Pepco Holdings (included in   short-term debt)	$	(34.1)	$	(157.4)
Money Pool Interest Accrued (included in interest accrued)	$	-	$	(.6)

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF EARNINGS (Unaudited)
	Three Months Ended June 30,				Six Months Ended June 30,
		2008		2007		2008		2007
		(Millions of dollars)
Operating Revenue	$	387.2	$	338.3	$	748.7	$	676.5
Operating Expenses
Fuel and purchased energy		273.4		243.0		518.7		466.8
Other operation and maintenance		42.9		37.3		89.0		76.9
Depreciation and amortization		25.1		17.4		49.2		34.5
Other taxes		5.6		4.0		11.5		9.7
Deferred electric service costs		(16.7)		(10.0)		8.0		16.0
Gain on sale of assets		-		(.1)		-		(.4)
Total Operating Expenses		330.3		291.6		676.4		603.5
Operating Income		56.9		46.7		72.3		73.0
Other Income (Expenses)
Interest and dividend income		.1		.4		.6		.8
Interest expense		(14.7)		(16.2)		(29.5)		(32.2)
Other income		.6		1.2		1.7		2.4
Other expense		(.3)		-		(.7)		-
Total Other Expenses		(14.3)		(14.6)		(27.9)		(29.0)
Income Before Income Tax Expense		42.6		32.1		44.4		44.0
Income Tax Expense		15.2		12.9		11.7		17.2
Income from Continuing Operations		27.4		19.2		32.7		26.8
Discontinued Operations (Note 12)
Income from operations (net of taxes of zero     for the three months ended June 30, 2008      and 2007, respectively, and zero and     $.1 million for the six months ended     June 30, 2008 and 2007, respectively)		-		-		-		.1
Net Income		27.4		19.2		32.7		26.9
Dividends on Redeemable Serial Preferred Stock		-		.1		.1		.1
Earnings Available for Common Stock		27.4		19.1		32.6		26.8
Retained Earnings at Beginning of Period		147.0		119.7		141.8		132.0
Dividends Paid to Parent		(31.0)		(10.0)		(31.0)		(30.0)
Retained Earnings at End of Period	$	143.4	$	128.8	$	143.4	$	128.8

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		June 30, 2008		December 31, 2007
	(Millions of dollars)
CURRENT ASSETS
Cash and cash equivalents		$	8.7	$	7.0
Restricted cash			8.4		9.5
Accounts receivable, less allowance for uncollectible accounts     of $5.3 million and $4.9 million, respectively			221.9		198.1
Fuel, materials and supplies - at average cost			13.7		14.1
Prepayments of income taxes			50.4		47.0
Prepaid expenses and other			71.2		16.8
Total Current Assets			374.3		292.5
INVESTMENTS AND OTHER ASSETS
Regulatory assets			796.8		818.0
Restricted funds held by trustee			5.0		6.8
Prepaid pension expense			7.3		8.5
Other			58.8		36.9
Total Investments and Other Assets			867.9		870.2
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment			2,156.6		2,078.0
Accumulated depreciation			(649.5)		(633.5)
Net Property, Plant and Equipment			1,507.1		1,444.5
TOTAL ASSETS		$	2,749.3	$	2,607.2

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

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)
LIABILITIES AND SHAREHOLDER’S EQUITY		June 30, 2008		December 31, 2007
	(Millions of dollars, except shares)
CURRENT LIABILITIES
Short-term debt		$	129.6	$	51.7
Current maturities of long-term debt			31.4		81.0
Accounts payable and accrued liabilities			166.8		128.9
Accounts payable to associated companies			93.0		18.3
Taxes accrued			41.3		30.2
Interest accrued			11.6		13.3
Liabilities and accrued interest related to  tax positions			6.4		26.6
Other			35.4		37.0
Total Current Liabilities			515.5		387.0
DEFERRED CREDITS
Regulatory liabilities			431.9		430.9
Deferred income taxes, net			423.7		386.3
Investment tax credits			10.5		11.1
Other postretirement benefit obligation			38.8		38.0
Other			29.4		21.2
Total Deferred Credits			934.3		887.5
LONG-TERM LIABILITIES
Long-term debt			361.1		415.7
Transition Bonds issued by ACE Funding			418.3		433.5
Total Long-Term Liabilities			779.4		849.2
COMMITMENTS AND CONTINGENCIES (NOTE 10)
REDEEMABLE SERIAL PREFERRED STOCK			6.2		6.2
SHAREHOLDER’S EQUITY
Common stock, $3.00 par value, authorized     25,000,000 shares, and 8,546,017 shares outstanding			25.6		25.6
Premium on stock and other capital contributions			344.9		309.9
Retained earnings			143.4		141.8
Total Shareholder’s Equity			513.9		477.3
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY		$	2,749.3	$	2,607.2

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

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ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
		Six Months Ended June 30,
			2008		2007
	(Millions of dollars)
OPERATING ACTIVITIES
Net income		$	32.7	$	26.9
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization			49.2		34.5
Deferred income taxes			34.3		25.1
Gain on sale of assets			-		(.4)
Changes in:
Accounts receivable			(23.8)		(25.7)
Accounts payable and accrued liabilities			116.8		18.8
Prepaid New Jersey sales and excise tax			(54.4)		(53.0)
Regulatory assets and liabilities			3.5		9.5
Interest and taxes accrued			(29.7)		(10.6)
Other changes in working capital			.1		(.1)
Net other operating			3.8		(1.0)
Net Cash From Operating Activities			132.5		24.0
INVESTING ACTIVITIES
Net investment in property, plant and equipment			(88.9)		(61.9)
Proceeds from sale of assets			1.0		9.0
Net other investing activities			2.3		1.7
Net Cash Used By Investing Activities			(85.6)		(51.2)
FINANCING ACTIVITIES
Dividends paid to Parent			(31.0)		(30.0)
Dividends paid on preferred stock			(.1)		(.1)
Capital contribution from Parent			35.0		-
Reacquisition of long-term debt			(119.4)		(30.3)
Issuances of short-term debt, net			77.9		87.6
Net other financing activities			(7.6)		(1.1)
Net Cash (Used By)/From Financing Activities			(45.2)		26.1
Net Increase/(Decrease) in Cash and Cash Equivalents			1.7		(1.1)
Cash and Cash Equivalents at Beginning of Period			7.0		5.5
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	8.7	$	4.4
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)		$	6.5	$	4.8

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ATLANTIC CITY ELECTRIC COMPANY

(1) ORGANIZATION

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

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

(2)  SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

ACE’s unaudited consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP).  Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted.  Therefore, these financial statements should be read along with the annual financial statements included in ACE’s Annual Report on Form 10-K for the year ended December 31, 2007.  In the opinion of ACE’s management, the consolidated financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly ACE’s financial condition as of June 30, 2008, in accordance with GAAP.  The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.  Interim results for the three and six months ended June 30, 2008 may not be indicative of results that will be realized for the full year ending December 31, 2008 since the sales of electric energy are seasonal.

FIN 46R, “Consolidation of Variable Interest Entities”

ACE has power purchase agreements (PPAs) with a number of entities, including three contracts between unaffiliated non-utility generators (NUGs) and ACE.  Due to a variable element in the pricing structure of the NUGs, ACE potentially assumes the variability in the operations of the plants related to these PPAs and, therefore, has a variable interest in the entities.  In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R (revised December 2003), entitled “Consolidation of Variable Interest Entities” (FIN 46R) and FASB Staff Position (FSP) FIN 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)” (FSP FIN 46(R)-6), ACE continued, during the second quarter of 2008, to conduct exhaustive efforts to obtain information from these entities, but was unable to obtain sufficient information to conduct the analysis required under FIN 46R to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary.  As a result, ACE has applied the scope

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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 June 30, 2008 and 2007 were approximately $82 million and $77 million, respectively, of which approximately $74 million and $70 million, respectively, related to power purchases under the NUGs.  Net power purchase activities with the counterparties to the NUGs for the six months ended June 30, 2008 and 2007 were approximately $171 million and $159 million, respectively, of which approximately $150 million and $143 million, respectively, related to power purchases under the NUGs.  ACE does not have exposure to loss under the NUGs because cost recovery will be achieved from its customers through regulated rates.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were $4.8 million and $5.1 million for the three months ended June 30, 2008 and 2007, respectively, and $10.2 million and $10.5 million for the six months ended June 30, 2008 and 2007, respectively.

(3)  NEWLY ADOPTED ACCOUNTING STANDARDS

SFAS No. 157, "Fair Value Measurements"

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

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

The provisions of SFAS No. 157 are to be applied prospectively, except for the initial impact on three specific items: (1) changes in fair value measurements of existing derivative

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financial instruments measured initially using the transaction price under EITF 02-3, (2) existing hybrid financial instruments measured initially at fair value using the transaction price and (3) blockage factor discounts.  Adjustments to these items required under SFAS No. 157 are to be recorded as a transition adjustment to beginning retained earnings in the year of adoption.

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

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

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

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

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

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entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet.  SFAS No. 159 does not eliminate disclosure requirements included in other accounting standards.

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

(4)  RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

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

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

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

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

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

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

On December 4, 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements–an Amendment of ARB No. 51” (SFAS No. 160), which amends Accounting Research Bulletin (ARB) No. 51 to establish accounting and reporting standards for a noncontrolling interest in a subsidiary and for the deconsolidation of a

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subsidiary.  It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.

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

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

FSP FAS 142-3, “Determination of the Useful Life of Intangible Assets”

On April 25, 2008, the FASB issued FSP Financial Accounting Standards (FAS) 142-3, “Determination of the Useful Life of Intangible Assets,” (FSP FAS 142-3) which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142).  The intent of FSP FAS 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combinations,” and other U.S. generally accepted accounting principles (GAAP).

In developing assumptions about renewal or extension used to determine the useful life of a recognized intangible asset, an entity should consider its own historical experience in renewing or extending similar arrangements; however, these assumptions should be adjusted for entity-specific factors as discussed in SFAS No. 142.  In the absence of that experience, an entity should consider the assumptions that market participants would use about renewal or extension (consistent with the highest and best use of the asset by market participants), adjusted for the entity-specific factors as discussed in SFAS No. 142.

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FSP FAS 142-3 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for ACE).  Early adoption is prohibited.  The guidance for determining the useful life of a recognized intangible asset in FSP FAS 142-3 shall be applied prospectively to intangible assets acquired after the effective date.  The disclosure requirements shall be applied prospectively to all intangible assets recognizedas of, and subsequent to, the effective date.  ACE is currently evaluating the impact FSP FAS 142 -3 may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

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

On May 9, 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162) which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP in the United States (the GAAP hierarchy).  Moving the GAAP hierarchy into the accounting literature appropriately directs the hierarchy to the reporting entity responsible for the content of the financial statements, rather than to the auditors.

SFAS No. 162 is effective sixty days following the Securities and Exchange Commission’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of ‘Present fairly in conformity with generally accepted accounting principles’.”  The application of SFAS No. 162 is not expected to result in a change in accounting; however, if it does, the accounting change must be reported as a change in accounting principle under SFAS No. 154, “Accounting Changes and Error Corrections.”  ACE is currently evaluating the impact SFAS No. 162 may have on its overall financial condition, results of operations, cash flows or footnote disclosure requirements.

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

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

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

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FSP APB 14-1 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for ACE).  FSP APB 14-1 shall be applied retrospectively to all periods presented.  Early adoption is not permitted.  ACE does not currently have any convertible debt instruments outstanding; however, these types of instruments may be considered for financing future endeavors.

(5)  SEGMENT INFORMATION

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

(6)  PENSION AND OTHER POSTRETIREMENT BENEFITS

ACE accounts for its participation in the Pepco Holdings benefit plans as participation in a multi-employer plan.  PHI’s pension and other postretirement net periodic benefit cost for the three months ended June 30, 2008, of $16.2 million includes $2.7 million for ACE’s allocated share.  PHI's pension and other postretirement net periodic benefit cost for the six months ended June 30, 2008, of $32.2 million includes $5.9 million for ACE's allocated share.

PHI’s pension and other postretirement net periodic benefit cost for the three months ended June 30, 2007, of $10.8 million includes $2.3 million for ACE’s allocated share.  PHI's pension and other postretirement net periodic benefit cost for the six months ended June 30, 2007, of $27.8 million includes $5.7 million for ACE's allocated share.

(7)  DEBT

In April 2008, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $5.1 million on Series 2002-1 Bonds, Class A-1 and $2.1 million on Series 2003-1.

During the first quarter of 2008, ACE purchased at par $25 million in aggregate principal amount of insured tax-exempt auction rate bonds issued by municipal authorities for the benefit of ACE.  These purchases were made in response to disruption in the market for municipal auction rate securities that made it difficult for the remarketing agent to successfully remarket the bonds.  During the second quarter of 2008, ACE purchased at par additional insured tax-exempt auction rate bonds as follows:

·   In April 2008, ACE purchased the following series of bonds: (i) $23.15 million of Pollution Control Revenue Refunding Bonds Series 2004A due 2029 issued by Salem County and (ii) $6.5 million of Pollution Control Revenue Refunding Bonds Series 2004B due 2029 issued by Cape May County.

These bonds are considered to be extinguished for accounting purposes; however ACE intends to hold the bonds, while monitoring the market and evaluating the options for remarketing the bonds to the public at some time in the future.

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

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

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

The payment for these VRDBs was financed by The Bank of New Yorkunder Standby Bond Purchase Agreements (SBPAs) for the respective series.  If these VRDBs cannot be remarketed by the remarketing agent prior to the first anniversary of the purchase of the VRDBs by the bond trustee, ACE will be obligated to redeem 1/10th of the principal amount of each series of VRDBs held by the bond trustee every six months thereafter.  While the VRDBs are held by the bond trustee, ACE is obligated to pay interest on such bonds at a rate equal to the prime rate or Libor plus 50 basis points.

During the second quarter of 2008, ACE redeemed at maturity the following Medium Term Notes:

·   In April 2008, $1 million of 6.77% Medium Term Notes.

·   In May 2008, (i) $21 million of 6.75% Medium Term Notes and (ii) $4 million of 6.73% Medium Term Notes.

·   In June 2008, (i) $4 million of 6.73% Medium Term Notes and (ii) $5 million of 6.71% Medium Term Notes.

(8)  INCOME TAXES

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2008		2007		2008		2007
Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect	6.6		6.8		7.2		6.6
Depreciation	(.5)		.3		(1.1)		.5
Tax credits	(.7)		(1.0)		(1.1)		(1.6)
Adjustment to prior years’ tax	-		-		-		(.2)
Change in estimates and interest related to uncertain          and effectively settled tax positions	(5.0)		(.6)		(13.3)		(.9)
AFUDC – Equity	-		-		(.5)		-
Service company cost allocation	.3		-		.2		-
Other, net	-		(.3)		-		(.3)
Consolidated Effective Income Tax Rate	35.7	%	40.2	%	26.4	%	39.1	%

ACE’s effective tax rates for the three months ended June 30, 2008 and 2007 were 35.7% and 40.2%, respectively.  The change in the rate resulted from certain depreciation book/tax differences and changes in estimates and interest related to uncertain and effectively settled tax positions (primarily related to mixed service costs discussed below).

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ACE’s effective tax rates for the six months ended June 30, 2008 and 2007 were 26.4% and 39.1%, respectively.  The change in the rate resulted from an increase in the change in estimates and interest related to uncertain and effectively settled tax positions (primarily related to a claim made for repair costs on prior year returns), and certain depreciation book/tax differences.

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

(9)  FAIR VALUE DISCLOSURES

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

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

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

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

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

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

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

The following table sets forth by level within the fair value hierarchy ACE's financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2008.  As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  ACE's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements at Reporting Date Using
	(Millions of dollars)
Description	June 30, 2008	Quoted Prices in Active Markets for Identical Instruments (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level  3)
ASSETS
Executive deferred   compensation plan assets	$ .3	$-	$  -	$ .3
	$ .3	$-	$  -	$ .3
LIABILITIES
Executive deferred   compensation plan liabilities	$ .8	$-	$  .8	$-
	$ .8	$-	$  .8	$-

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

	Deferred Compensation Plan Assets
Beginning balance as of January 1, 2008	$  .3
Total gains or (losses) (realized/unrealized)
Included in earnings	-
Included in other comprehensive income	-
Purchases and issuances	-
Settlements	-
Transfers in and/or out of Level 3	-
Ending balance as of June 30, 2008	$  .3
Gains or (losses) (realized and unrealized) included in earnings for the period above are reported in Other Operation and Maintenance Expense as follows:	Other Operation and Maintenance Expense
Total gains included in earnings for the period above	$  -
Change in unrealized gains relating to assets still held at reporting date	$  -

(10)  COMMITMENTS AND CONTINGENCIES

REGULATORY AND OTHER MATTERS

In June 2007, ACE filed with the New Jersey Board of Public Utilities (NJBPU) an application for permission:

·   to decrease the Non Utility Generation Charge, which is intended primarily to allow ACE to recover the above-market component of payments made by ACE under non-utility generation contracts and stranded costs associated with those commitments (NGC), which had an over-recovery balance, and

·   to increase components of its Societal Benefits Charge, which is intended to allow ACE to recover certain costs involved with various NJBPU-mandated social programs (SBC), which had an under-recovery balance.

In an order dated May 20, 2008, the NJBPU approved a Stipulation of Settlement under which the net impact of the adjustments to the NGC and the SBC, including associated changes in sales and use tax, is an overall rate decrease of approximately $117.3 million over the period June 1, 2008 through May 31, 2009 (the final rate changes will be based upon actual data through March 2008).  ACE anticipates that the revised rates will remain in effect until May 31, 2009, subject to an annual true-up and change each year thereafter.

ACE Sale of B.L. England Generating Facility

In February 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy

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

Environmental Litigation

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

Delilah Road Landfill Site.  In 1991, the New Jersey Department of Environmental Protection (NJDEP) identified ACE as a potentially responsible party (PRP) at the Delilah Road Landfill site in Egg Harbor Township, New Jersey.  In 1993, ACE, along with other PRPs, signed an administrative consent order with NJDEP to remediate the site.  The soil cap remedy for the site has been implemented and in August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site.  Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years.  In September 2007, NJDEP approved the PRP group’s petition to conduct semi-annual, rather than quarterly, ground water monitoring for two years and deferred until the end of the two-year period a decision on the PRP group’s request for annual groundwater monitoring thereafter.  In August 2007, the PRP group agreed to reimburse the costs of the U.S. Environmental Protection Agency (EPA) in the amount of $81,400 in full satisfaction of EPA’s claims for all past and future response costs relating to the site (of which ACE’s share is one-third).  Effective April 11, 2008, EPA and the PRP group entered into a settlement agreement which will allow EPA to reopen the settlement in the event of new information or unknown conditions at the site.  Based on information currently available, ACE anticipates that its share of additional cost associated with this site for post-remedy operation and maintenance will be approximately $555,000 to $600,000.  ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial position, results of operations or cash flows.

Frontier Chemical Site.  In June 2007, ACE received a letter from the New York Department of Environmental Conservation (NYDEC) identifying ACE as a PRP at the Frontier Chemical Waste Processing Company site in Niagara Falls, N.Y. based on hazardous waste

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manifests indicating that ACE sent in excess of 7,500 gallons of manifested hazardous waste to the site.  ACE has entered into an agreement with the other parties identified as PRPs to form the PRP group and has informed NYDEC that it has entered into good faith negotiations with the PRP group to address ACE’s responsibility at the site.  ACE believes that its responsibility at the site will not have a material adverse effect on its financial position, results of operations or cash flows.

IRS Mixed Service Cost Issue

During 2001, ACE changed its method of accounting with respect to capitalizable construction costs for income tax purposes.  The change allowed ACE to accelerate the deduction of certain expenses that were previously capitalized and depreciated.  Through December 31, 2005, these accelerated deductions generated incremental tax cash flow benefits of approximately $49 million, primarily attributable to its 2001 tax returns.

In 2005, the Treasury Department issued proposed regulations that, if adopted in their current form, would require ACE to change its method of accounting with respect to capitalizable construction costs for income tax purposes for tax periods beginning in 2005.  Based on the proposed regulations, PHI in its 2005 federal tax return adopted an alternative method of accounting for capitalizable construction costs that management believed would be acceptable to the IRS.

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

In February 2006, PHI paid approximately $121 million of taxes (a portion of which is attributable to ACE) to cover the amount of additional taxes and interest that management estimated to be payable for the years 2001 through 2004 based on the method of tax accounting that PHI, pursuant to the proposed regulations, adopted on its 2005 tax return.  In June 2008, PHI received from the Appeals Office an offer of settlement pertaining to ACE for the tax years 2001 through 2004.  ACE is substantially in agreement with this proposed settlement.  Based on the terms of the proposal, ACE expects the final settlement amount to be less than the amount previously deposited.  Accordingly, in the quarter ended June 30, 2008, ACE recorded after-tax interest income of $2.2million and a net reduction in its liability for unrecognized tax benefits of $2.1 million.

(11) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries including ACE.  The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods.  PHI Service Company costs directly charged or allocated

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to ACE for the three and six months ended June 30, 2008 and 2007 were $21.9 million and $19.3 million and $43.5 million and $39.4 million, respectively.

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2008		2007		2008		2007
	(Millions of dollars)
Income (Expense)
Purchased power from Conectiv Energy Supply (a)	$	(35.9)	$	(22.2)	$	(57.7)	$	(41.0)	(
Meter reading services provided by    Millennium Account Services LLC (b)	$	(.9)	$	(.9)	$	(1.9)	$	(1.9)
Intercompany lease transactions (b)		(.4)		(.3)		(.7)		(.7)
Intercompany use revenue (c)		.5		.4		1.0		1.0
Intercompany use expense (c)		(.5)		(.4)		(1.0)		(1.0)

     (a) Included in fuel and purchased energy.

     (b) Included in other operation and maintenance.

     (c) Included in operating revenue.

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

		June 30, 2008	December 31, 2007
Asset (Liability)		(Millions of dollars)
Payable to Related Party (current)
PHI Service Company	$	(9.9)	$	(10.4)
Conectiv Energy Supply		(82.6)		(7.8)
The items listed above are included in the “Accounts payable to associated companies” balance on   the Consolidated Balance Sheet of $93.0 million and $18.3 million at June 30, 2008 and   December 31, 2007, respectively.

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(12)  DISCONTINUED OPERATIONS

As discussed in Note (10) “Commitments and Contingencies,” herein, in February 2007, ACE completed the sale of the B.L. England generating facility.  B.L. England comprised a significant component of ACE’s generation operations and its sale required discontinued operations presentation under SFAS No. 144, “Accounting for the Impairment or Disposal of Long Lived Assets,” on ACE’s Consolidated Statement of Earnings for the three and six months ended June 30, 2007.

The following table summarizes discontinued operations information for the three and six months ended June 30, 2007 (millions of dollars):

	For the Three Months Ended June 30, 2007		For the Six Months Ended June 30, 2007
	(Millions of dollars)
Operating Revenue	$	-	$	9.7
Income Before Income Tax Expense	$	-	$	.2
Net Income	$	-	$	.1

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

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

Registrants	Page No.
Pepco Holdings	113
Pepco	154
DPL	162
ACE	172

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

  AND RESULTS OF OPERATIONS

PEPCO HOLDINGS, INC.

GENERAL OVERVIEW

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

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

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

For the three months ended June 30, 2008 and 2007, respectively, PHI’s Power Delivery operations produced 51% and 56% of PHI’s consolidated operating revenues (including revenues from intercompany transactions) and 133% and 73% of PHI’s consolidated operating income (including income from intercompany transactions).  For the six months ended June 30, 2008 and 2007, respectively, PHI’s Power Delivery operations produced 50% and 57% of PHI’s consolidated operating revenues (including revenues from intercompany transactions) and 76% and 67% of PHI’s consolidated operating income (including income from intercompany transactions).

For the three months ended June 30, 2008 and 2007, the distribution, transmission and default supply of electric power accounted for 94% of Power Delivery’s operating revenues and the delivery and supply of natural gas contributed 6% of Power Delivery’s operating revenues.  For the six months ended June 30, 2008 and 2007, respectively, the distribution, transmission and default supply of electric power accounted for 92% and 93% of Power Delivery’s operating revenues and the delivery and supply of natural gas contributed 8% and 7% of Power Delivery’s operating revenues.  Power Delivery represents one operating segment for financial reporting purposes.

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

Delaware	Standard Offer Service (SOS)
District of Columbia	SOS

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Maryland	SOS
New Jersey	Basic Generation Service
Virginia	Default Service (prior to January 2, 2008)

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

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

The profitability of the Power Delivery business depends on its ability to recover costs and earn a reasonable return on its capital investments through the rates it is permitted to charge.  Power Delivery’s operating results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year.  Operating results also can be affected by economic conditions, energy prices and the impact of energy efficiency measures on customer usage of electricity.

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

The Competitive Energy business provides competitive generation, marketing and supply of electricity and gas, and related energy management services primarily in the mid-Atlantic region. These operations are conducted through subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv Energy) and Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), each of which is treated as a separate operating segment for financial reporting purposes.  For the three months ended June 30, 2008 and 2007, theoperating revenues of the Competitive Energy business (including revenue from intercompany transactions) were equal to 56%, and 48%, respectively, of PHI’s consolidated operating revenues, and the operating income of the Competitive Energy business (including operating income from intercompany transactions) was 59% and 17% of PHI’s consolidated operating income for the three months ended June 30, 2008 and 2007, respectively.  For the six months ended June 30, 2008 and 2007, the operating revenues of the Competitive Energy business (including intercompany amounts) were equal to 56% and 47%, respectively, of PHI’s

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consolidated operating revenues, and the operating income of the Competitive Energy business (including operating income from intercompany transactions) was 50% and 22%, respectively, of PHI’s consolidated operating income for the six months ended June 30, 2008 and 2007, respectively.  For the three months ended June 30, 2008 and 2007, amounts equal to 6% and 10% respectively, of the operating revenues of the Competitive Energy business were attributable to electric energy and capacity, and natural gas sold to the Power Delivery segment.  For the six months ended June 30, 2008 and 2007, amounts equal to 6% and 10% respectively, of the operating revenues of the Competitive Energy business were attributed to electric energy and capacity and natural gas sold to the Power Delivery segment.

· Conectiv Energy provides wholesale electric power, capacity and ancillary services in the wholesale markets and also supplies electricity to other wholesale market participants under long- and short-term bilateral contracts.  Conectiv Energy supplies electric power to Pepco, DPL and ACE to satisfy a portion of their Default Electricity Supply load, as well as default electricity supply load shares of other utilities within the PJM Interconnection, LLC (PJM) Regional Transmission Organization (RTO) and Independent System Operator - New England (ISONE) wholesale markets.  PHI refers to these activities as Merchant Generation & Load Service.  Conectiv Energy obtains the electricity required to meet its Merchant Generation & Load Service power supply obligations from its own generation plants, bilateral contract purchases from other wholesale market participants, and purchases in the wholesale market.  Conectiv Energy’s primary fuel source for its generation plants is natural gas.  Conectiv Energy manages its natural gas supply using a portfolio of long-term, firm storage and transportation contracts, and a variety of derivative instruments.  Conectiv Energy also sells natural gas and fuel oil to very large end-users and to wholesale market participants under bilateral agreements.  PHI refers to these sales operations as Energy Marketing.

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

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

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

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy lease investments with a book value at June 30, 2008 of approximately $1.3 billion.  This activity constitutes a fourth operating segment, which is designated as “Other Non-Regulated,” for financial reporting purposes.  For a discussion of PHI’s cross-border energy lease investments, see “Regulatory and Other Matters — PHI’s Cross-Border Energy Lease Investments” in this Management’s Discussion and Analysis.

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

EARNINGS OVERVIEW

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

PHI’s net income for the three months ended June 30, 2008 was $15.0 million, or $.07 per share, compared to $57.2 million, or $.30 per share, for the three months ended June 30, 2007.

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

Adjustment to the equity value of cross-border energy lease investments at PCI under Financial Accounting Standards Board (FASB) Staff Position No. 13-2, “Accounting for a Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged-Lease Transaction” (FSP 13-2) to reflect the impact of a change in assumptions regarding the estimated timing of the tax benefits	$	(86.0)
Additional interest accrued under FIN 48 related to the estimated federal and state income tax obligations from the change in assumptions regarding the estimated timing of the tax benefits on cross-border energy lease investments	$	(6.9)

Excluding the items listed above for the three months ended June 30, 2008, net income would have been $107.9 million, or $.53 per share, compared with $57.2 million, or $.30 per share for the three months ended June 30, 2007.

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

	2008	2007	Change
Power Delivery	$  74.4	$  46.4	$  28.0
Conectiv Energy	20.6	1.8	18.8
Pepco Energy Services	16.3	10.7	5.6
Other Non-Regulated	(83.1)	15.4	(98.5)
Corp. & Other	(13.2)	(17.1)	3.9
Total PHI Net Income	$ 15.0	$  57.2	$  (42.2)

Discussion of Operating Segment Net Income Variances:

Power Delivery's $28.0 million increase in earnings is primarily due to the following:

·   $15.1 million increase due to the impact of the distribution base rate orders ($10.6 million related to Maryland which became effective in June 2007 for Pepco and DPL, and $4.5 million related to the District of Columbia, which became effective in February 2008 for Pepco).

·   $4.6 million increase due to FERC network transmission formula rate changes in June 2007 and 2008.

·   $6.6 million increase due to net favorable income tax adjustments primarily related to Financial Accounting Standards Board Interpretation No. (FIN) 48 interest impact.

·   $2.2 million increase primarily due to higher sales (primarily increased customer usage, net of an unfavorable impact of weather compared to 2007).

·   $1.6 million increase due to higher Default Electricity Supply margins primarily as a result of the sale of DPL’s Virginia electric distribution and default supply operations, which eliminated negative margins associated with Virginia Default Electricity Supply sales.

·   $4.6 million decrease due to higher operating and maintenance costs (primarily higher preventative maintenance and system operation costs, employee-related costs and bad debt expense).

Conectiv Energy's $18.8 million increase in earnings is primarily due to the following:

·   $19.8 million increase in Merchant Generation & Load Service primarily due to (i) an increase of $10.3 million primarily due to higher spark spreads in 2008, (ii) an increase of $6.1 million due to higher PJM capacity prices net of capacity hedges and (iii) an increase of $4.1 million due to a gain related to coal contracts accounted for at fair value.

·   $2.0 million decrease primarily due to higher plant maintenance costs.

Pepco Energy Services' $5.6 million increase in earnings is primarily due the following:

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·   $5.8 million increase from its retail energy supply business resulting from a $4.0 million gain related to certain hedges of congestion risk accounted for at fair value, $2.9 million related to increased generation output, and $2.5 million related to more favorable congestion costs; partially offset by higher electric supply costs.

Other Non-Regulated’s $98.5 million decrease in earnings is primarily due to the following:

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

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

·   $6.2 million decrease primarily due to favorable valuation of certain other PCI portfolio investments in 2007.

Corporate and Other’s $3.9 million increase in earnings is primarily due to prior year tax audit adjustments (tax benefits recorded by other segments and eliminated in consolidation through Corporate and Other), and lower interest expense and corporate governance costs.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

PHI’s net income for the six months ended June 30, 2008 was $114.2 million, or $.57 per share, compared to $108.8 million, or $.56 per share, for the six months ended June 30, 2007.

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

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

Excluding the items listed above for the six months ended June 30, 2008, net income would have been $207.1 million, or $1.03 per share, compared with $108.8 million, or $.56 per share for the six months ended June 30, 2007.

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

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	2008	2007	Change
Power Delivery	$  121.8	$   79.6	$  42.2
Conectiv Energy	69.0	20.8	48.2
Pepco Energy Services	24.9	13.3	11.6
Other Non-Regulated	(73.5)	26.2	(99.7)
Corp. & Other	(28.0)	(31.1)	3.1
Total PHI Net Income	$  114.2	$ 108.8	$   5.4

Discussion of Operating Segment Net Income Variances:

Power Delivery's $42.2 million increase in earnings is primarily due to the following:

·   $27.1 million increase due to the impact of the distribution base rate orders ($20.2 million related to Maryland which became effective in June 2007 for Pepco and DPL, and $6.9 million related to the District of Columbia, which became effective in February 2008 for Pepco).

·   $13.6 million increase due to favorable income tax adjustments primarily related to FIN 48 interest impact.

·   $10.6 million increase due to FERC network transmission formula rate changes in June 2007 and 2008.

·   $4.7 million increase due to higher Default Electricity Supply margins primarily as a result of the sale of DPL’s Virginia electric distribution and default supply operations, which eliminated negative margins associated with Virginia Default Electricity Supply sales.

·   $8.7 million decrease due to higher operating and maintenance costs (primarily higher preventative maintenance and system operation costs, employee-related costs and bad debt expense).

·   $1.5 million decrease primarily due to lower sales (primarily unfavorable impact of weather compared to 2007).

Conectiv Energy's $48.2 million increase in earnings is primarily due to the following:

·   $50.3 million increase in Merchant Generation & Load Service primarily due to (i) an increase of $21.9 million primarily due to short term sales of firm natural gas and natural gas transportation and storage rights, gains on natural gas positions used to provide economic protection for certain power positions, and Conectiv Energy's generation units' operating flexibility and dual-fuel capability in conjunction with short-term power and fuel price volatility, (ii) an increase of $11.8 million due to higher PJM capacity prices net of capacity hedges, (iii) an increase of $7.7 million due to a gain related to coal contracts accounted for at fair value and (iv) an increase of $5.1 million due to a fair value gain related to power and fuel hedge ineffectiveness.

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Pepco Energy Services' $11.6 million increase in earnings is primarily due to the following:

·   $14.3 million increase from its retail energy supply business resulting from $6.5 million related to more favorable congestion costs, a $4.1 million gain related to certain hedges of congestion risk accounted for at fair value, and $3.6 million related to increased generation output.

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

Other Non-Regulated’s $99.7 million decrease in earnings is primarily due to the following:

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

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

·   $9.7 million decrease primarily due to favorable valuation of certain other PCI portfolio investments in 2007.

As a result of our revised assumptions regarding the timing of cash flows under FSP 13-2, PHI expects annual net earnings from cross-border energy lease investments to decrease by approximately $20 million annually over the near-term, including approximately $7 million of interest expense.  In addition, PHI expects annual cash flow from cross-border energy lease investments to decline annually by approximately $21 million.

Corporate and Other’s $3.1 million increase in earnings is primarily due to lower interest expense and corporate governance costs.

CONSOLIDATED RESULTS OF OPERATIONS

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

Operating Revenue

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

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	2008		2007		Change
Power Delivery	$	1,296.2	$	1,162.3	$	133.9
Conectiv Energy		789.7		478.2		311.5
Pepco Energy Services		631.3		522.6		108.7
Other Non-Regulated		(105.5)		19.1		(124.6)
Corp. & Other		(93.5)		(97.9)		4.4
Total Operating Revenue	$	2,518.2	$	2,084.3	$	433.9

Power Delivery Business

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

	2008		2007		Change
Regulated T&D Electric Revenue	$	419.4	$	367.5	$	51.9
Default Supply Revenue		778.8		713.7		65.1
Other Electric Revenue		15.0		16.0		(1.0)
Total Electric Operating Revenue		1,213.2		1,097.2		116.0
Regulated Gas Revenue		35.9		40.5		(4.6)
Other Gas Revenue		47.1		24.6		22.5
Total Gas Operating Revenue		83.0		65.1		17.9
Total Power Delivery Operating Revenue	$	1,296.2	$	1,162.3	$	133.9

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

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

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

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

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

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In response to an order issued by the New Jersey Board of Public Utilities (NJBPU) regarding changes to ACE’s retail transmission rates, ACE has established deferred accounting treatment for the difference between the rates that ACE is authorized to charge its customers for the transmission of default electricity supply and the cost that ACE incurs based on FERC-approved transmission formula rates.  Under the deferral arrangement, any over or under recovery is deferred as part of Deferred Electric Service Costs pending an adjustment of retail rates in a future proceeding.  As a consequence of the order, effective January 1, 2008, ACE’s retail transmission revenue is being recorded as Default Supply Revenue, rather than as Regulated T&D Electric Revenue, thereby conforming to the practice of PHI’s other utility subsidiaries, which previously established deferred accounting treatment for any over or under recovery of retail transmission rates relative to the cost incurred based on FERC-approved transmission formula rates.  In addition, ACE’s retail transmission revenue for the period prior to January 1, 2008 has been reclassified to Default Supply Revenue in order to conform to current period presentation.

Electric Operating Revenue

Regulated T&D Electric Revenue
	2008		2007		Change
Residential	$	131.7	$	123.8	$	7.9
Commercial		193.4		181.3		12.1
Industrial		7.5		6.3		1.2
Other		86.8		56.1		30.7
Total Regulated T&D Electric Revenue	$	419.4	$	367.5	$	51.9

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))
	2008		2007		Change
Residential		3,675		3,684		(9)
Commercial		7,353		7,302		51
Industrial		1,039		1,103		(64)
Other		56		56		-
Total Regulated T&D Electric Sales		12,123		12,145		(22)

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Regulated T&D Electric Customers (in thousands)
	2008		2007		Change
Residential		1,604		1,612		(8)
Commercial		195		198		(3)
Industrial		2		1		1
Other		2		2		-
Total Regulated T&D Electric Customers		1,803		1,813		(10)

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

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

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

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

Regulated T&D Electric Revenue increased by $51.9 million primarily due to the following:  (i) $20.8 million increase in Other Regulated T&D Electric Revenue from the resale of energy and capacity purchased under the power purchase agreement between Panda-Brandywine, L.P. (Panda) and Pepco (the Panda PPA), (offset in Fuel and Purchased Energy and Other Services Cost of Sales), (ii) $12.3 million increase due to differences in consumption among the various customer rate classes, (iii) $10.1 million increase due to a distribution rate increase under the 2007 Maryland Rate Orders that became effective in June 2007, including a positive $2.6 million Revenue Decoupling Adjustment, (iv) $7.7 million increase due to a District of Columbia distribution rate increase that became effective in February 2008, (v) $6.6 million increase in transmission service revenue primarily due to changes in the FERC formula rates in June 2008 and 2007, (vi) $3.4 million increase due to a distribution rate change as part of an increase in the New Jersey Societal Benefit Charge that became effective in June 2008 (offset in Deferred Electric Service Costs) partially offset by, (vii) $4.0 million decrease due to lower weather-related sales (a 21% decrease in Heating Degree Days and a 3% decrease in Cooling Degree Days), (viii) $2.8 million decrease due to the sale of DPL’s Virginia retail electric distribution business in January 2008, and (ix) $2.2 million decrease due to lower pass-through revenue primarily resulting from tax rate decreases in the District of Columbia (primarily offset in Other Taxes).

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Default Electricity Supply

Default Supply Revenue
	2008		2007		Change
Residential	$	389.0	$	369.8	$	19.2
Commercial		278.1		258.7		19.4
Industrial		24.1		24.1		-
Other		87.6		61.1		26.5
Total Default Supply Revenue	$	778.8	$	713.7	$	65.1

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

Default Electricity Supply Sales (GWh)
	2008		2007		Change
Residential		3,552		3,580		(28)
Commercial		2,414		2,421		(7)
Industrial		191		238		(47)
Other		24		36		(12)
Total Default Electricity Supply Sales		6,181		6,275		(94)

Default Electricity Supply Customers (in thousands)
	2008		2007		Change
Residential		1,562		1,580		(18)
Commercial		166		167		(1)
Industrial		1		1		-
Other		2		2		-
Total Default Electricity Supply Customers		1,731		1,750		(19)

The change in the number of Default Electricity Supply customers was primarily due to the sale of DPL’s Virginia retail electric distribution business on January 2, 2008, in connection with which the purchaser assumed the associated Default Supply obligations.  This sale resulted in a decrease of approximately 19,000 residential customers and 3,000 commercial customers.

Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales, increased by $65.1 million primarily due to the following:  (i) $40.6 million increase in market-based Default Electricity Supply rates, (ii) $28.5 million increase in wholesale energy revenues due to the sale in PJM RTO at higher market prices of electricity purchased from NUGs, (iii) $19.7 million increase due to differences in consumption among the various customer rate classes, partially offset by (iv) $10.9 million decrease due to lower weather-related sales (21% decrease in Heating Degree Days and a 3% decrease in Cooling Degree Days), (v) $7.2 million decrease due to the sale of DPL’s Virginia retail electric

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distribution business, and (vi) $5.6 million decrease primarily due to commercial and industrial customers electing to purchase an increased amount of electricity from competitive suppliers.

Gas Operating Revenue

Regulated Gas Revenue
	2008		2007		Change
			$
Residential	$	20.3		23.1	$	(2.8)
Commercial		12.1		13.6		(1.5)
Industrial		1.6		2.3		(.7)
Transportation and Other		1.9		1.5		.4
Total Regulated Gas Sales	$	35.9	$	40.5	$	(4.6)

Regulated Gas Sales (billion cubic feet)
	2008		2007		Change
Residential		1.0		1.0		-
Commercial		.7		.8		(.1)
Industrial		.1		.2		(.1)
Transportation and Other		1.6		1.5		.1
Total Regulated Gas Sales		3.4		3.5		(.1)

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

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

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

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

Regulated Gas Revenue decreased by $4.6 million primarily due to (i) $2.3 million decrease due to lower weather-related sales (a 17% decrease in Heating Degree Days) and (ii) $1.6 million decrease due to differences in consumption among the various customer rate classes.

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Other Gas Revenue

Other Gas Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales, increased by $22.5 million primarily due to higher off-system sales of which (i) $14.5 million was attributable to an increase in market prices, and (ii) $8.2 million was attributable to an increase in demand from electric generators and gas marketers that DPL was able to fulfill due to available pipeline capacity.  Higher available capacity resulted from lower demand for natural gas from regulated customers caused by warmer weather than 2007.

Competitive Energy Businesses

Conectiv Energy

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

Operating Revenues of the Conectiv Energy segment are derived primarily from the sale of electricity.  The primary components of its Costs of Sales are fuel and purchased power.  Because fuel and electricity prices tend to move in tandem, price changes in these commodities from period to period can have a significant impact on Operating Revenue and Costs of Sales without signifying any change in the performance of the Conectiv Energy segment.  Conectiv Energy also uses a number of and various types of derivative contracts to lock in sales margins, and to economically hedge its power and fuel purchases and sales.  Gains and losses on derivative contracts are netted in revenue and cost of sales as appropriate under the applicable accounting rules.  For these reasons, PHI from a managerial standpoint focuses on gross margin as a measure of performance.

Conectiv Energy Gross Margin

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

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

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Conectiv Energy Gross Margin and Operating Statistics	Three Months Ended June 30,				Change
		2008		2007
Operating Revenue ($ millions):
Merchant Generation & Load Service	$	487.7	$	228.4		$	259.3
Energy Marketing		302.0		249.8			52.2
Total Operating Revenue1	$	789.7	$	478.2		$	311.5
Cost of Sales ($ millions):
Merchant Generation & Load Service	$	402.8	$	177.0		$	225.8
Energy Marketing		293.7		242.3			51.4
Total Cost of Sales2	$	696.5	$	419.3		$	277.2
Gross Margin ($ millions):
Merchant Generation & Load Service	$	84.9	$	51.4		$	33.5
Energy Marketing		8.3		7.5			.8
Total Gross Margin	$	93.2	$	58.9		$	34.3
Generation Fuel and Purchased Power Expenses ($ millions) 3:
Generation Fuel Expenses 4,5
Natural Gas	$	67.8	$	51.1		$	16.7
Coal		12.7		15.3			(2.6)
Oil		14.5		3.4			11.1
Other6		0.2		.5			(.3)
Total Generation Fuel Expenses	$	95.2	$	70.3		$	24.9
Purchased Power Expenses 5	$	214.4	$	95.0		$	119.4
Statistics:
Generation Output (MWh):
Base-Load 7		367,891		497,531			(129,640)
Mid-Merit (Combined Cycle) 8		588,430		625,111			(36,681)
Mid-Merit (Oil Fired) 9		67,719		24,853			42,866
Peaking		41,624		12,390			29,234
Tolled Generation		28,641		12,119			16,522
Total		1,094,305		1,172,004			(77,699)
Load Service Volume (MWh) 10		2,335,027		1,593,697			741,330
Average Power Sales Price 11 ($/MWh):
Generation Sales 4	$	139.01	$	78.98		$	60.03
Non-Generation Sales 12	$	87.32	$	70.96		$	16.36
Total	$	102.08	$	73.52		$	28.56
Average on-peak spot power price at PJM East Hub ($/MWh) 13	$	109.29	$	73.63		$	35.66
Average around-the-clock spot power price at PJM East Hub ($/MWh) 13	$	87.85	$	59.57		$	28.28
Average spot natural gas price at market area M3 ($/MMBtu)14	$	12.13	$	8.22		$	3.91
Weather (degree days at Philadelphia Airport): 15
Heating degree days		410		507			(97)
Cooling degree days		393		398			(5)

1 Includes $88.2 million and $96.3 million of affiliate transactions for 2008 and 2007, respectively.

2 Includes $.6 million and $.6 million of affiliate transactions for 2008 and 2007, respectively.  Also, excludes depreciation and amortization expense of $9.2 million and $9.3 million, respectively.

3 Consists solely of Merchant Generation & Load Service expenses; does not include the cost of fuel not consumed by the power plants and intercompany tolling expenses.

4 Includes tolled generation.

5 Includes associated hedging gains and losses.

6 Includes emissions expenses, fuel additives, and other fuel-related costs.

7 Edge Moor Units 3 and 4 and Deepwater Unit 6.

8 Hay Road and Bethlehem, all units.

9 Edge Moor Unit 5 and Deepwater Unit 1.

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.

Conectiv Energy’s revenue and cost of sales are higher in 2008 primarily due to increased default electricity supply volumes and higher energy commodity prices.  In 2008, Conectiv

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Energy expanded its default electricity supply business into the Independent System Operator - New England transmission organization (ISONE).

Merchant Generation & Load Service gross margin increased approximately $34 million primarily due to:

·   An increase of approximately $17 million in generation margins due to higher spark spreads in 2008.

·   An increase of approximately $10 million due to higher PJM capacity prices net of capacity hedges.  This is primarily the result of the implementation by PJM of the Reliability Pricing Model (RPM) on June 1, 2007.

·   An increase of approximately $7 million due to the application of fair value accounting treatment with respect to coal contracts.

Pepco Energy Services

Pepco Energy Services’ operating revenue increased $108.7 million primarily due to an increase of $108.2 million due to higher volumes of retail electric load served at higher prices in 2008 due to customer acquisitions.

Other Non-Regulated

Other Non-Regulated revenues decreased by $124.6 million from $19.1 million for the three months ended June 30, 2007 to $(105.5) million for the three months ended June 30, 2008.  As discussed in the Earnings Overview, a non-cash charge of $124.4 million was recorded in the quarter ended June 30, 2008 as a result of revised assumptions regarding the estimated timing of tax benefits from PCI’s cross-border energy lease investments.  In accordance with FSP 13-2, this charge has been recorded as a reduction to lease revenue from these transactions, which is included in Other Non-Regulated revenues.

Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2008		2007		Change
Power Delivery	$	827.3	$	740.8	$	86.5
Conectiv Energy		696.5		419.3		277.2
Pepco Energy Services		580.5		483.6		96.9
Corp. & Other		(92.1)		(96.7)		4.6
Total	$	2,012.2	$	1,547.0	$	465.2

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Power Delivery Business

Power Delivery’s Fuel and Purchased Energy, which is primarily associated with Default Electric Supply sales, increased by $86.5 million primarily due to (i) $60.7 million increase in average energy costs, the result of new Default Electricity Supply contracts, (ii) $34.0 million increase primarily due to differences in consumption among the various customer rate classes, (iii) $20.8 million increase for energy and capacity purchased under the Panda PPA (offset in Regulated T&D Electric Revenue), partially offset by (iv) $14.0 million decrease due to lower weather-related sales, (v) $9.8 million decrease due to the sale of DPL’s Virginia retail electric distribution business including Default Supply obligations on January 2, 2008 and (vi) $5.2 million decrease primarily due to a lower level of over-recovery of natural gas supply costs resulting in a reduction in the Deferred Gas Fuel deferral balance.  Fuel and Purchased Energy expense is substantially offset in Default Supply Revenue, Regulated Gas Revenue, and Other Gas Revenue.

Competitive Energy Business

Conectiv Energy

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 $96.9 million primarily due to an increase of $95.0 million due to higher volumes of purchased electricity at higher prices in 2008 to serve increased retail customer load.

Other Operation and Maintenance

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

	2008		2007		Change
Power Delivery	$	172.4	$	156.4	$	16.0
Conectiv Energy		42.1		38.5		3.6
Pepco Energy Services		21.0		17.7		3.3
Other Non-Regulated		.3		.6		(.3)
Corp. & Other		(5.7)		(2.4)		(3.3)
Total	$	230.1	$	210.8	$	19.3

Other Operation and Maintenance expenses of the Power Delivery segment increased by $16.0 million primarily due to (i) $7.8 million increase primarily in preventative maintenance and system operation costs, (ii) $6.9 million increase in costs associated with Default Electricity Supply primarily due to net over-recovery of bad debt expenses (substantially offset in Default Supply Revenue), (iii) $2.1 million increase in employee-related costs primarily related to updated assumptions underlying pension and other post-employment benefit liabilities, (iv) $1.7 million increase in legal expenses, (v) $1.2 million increase due to higher bad debt expenses (partially offset in Deferred Electric Service Costs), and (vi) $1.2 million increase in Demand

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Side Management program costs (offset in Deferred Electric Service Costs), partially offset by (vii) $3.7 million decrease in regulatory expense and (viii) $3.0 million decrease due to various construction project write-offs in 2007 related to customer requested work.

Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, increased by $6.7 million to income of $16.7 million in 2008 from income of $10.0 million in 2007.  The increase was primarily due to (i) $27.2 million net under-recovery associated with deferred energy costs, and (ii) $2.0 million net under-recovery associated with deferred transmission expenses, partially offset by (iii) $22.4 million net over-recovery associated with non-utility generation contracts between ACE and unaffiliated third parties.

Income Tax Expense

PHI’s effective tax rates for the three months ended June 30, 2008 and 2007 were 65.3% and 33.4%, respectively.  The increase in the effective tax rate was primarily driven by limited state tax benefits related to the charge taken on the cross-border energy lease investments as further discussed in Note (2) and Note (13).  In addition, the change in the rate was affected by a substantial increase in interest on uncertain tax positions related to the cross-border energy lease investments and certain prior period adjustments for Pepco. These changes were offset by interest benefits related to uncertain tax positions recorded for the tentative settlement with the IRS on the mixed service cost issue (as further discussed below and in Note (13)), and the June 2008 receipt of interest of $3.5 million ($2.2 million after-tax) from the state of Maryland with respect to a tax refund received during the third quarter of 2007.

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

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

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

Operating Revenue

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

	2008		2007		Change
Power Delivery	$	2,591.7	$	2,437.4	$	154.3
Conectiv Energy		1,612.4		974.3		638.1
Pepco Energy Services		1,252.0		1,032.5		219.5
Other Non-Regulated		(86.9)		38.4		(125.3)
Corp. & Other		(210.1)		(219.5)		9.4
Total Operating Revenue	$	5,159.1	$	4,263.1	$	896.0

Power Delivery Business

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

	2008		2007		Change
Regulated T&D Electric Revenue	$	799.4	$	718.5	$	80.9
Default Supply Revenue		1,562.7		1,508.5		54.2
Other Electric Revenue		30.9		32.5		(1.6	)
Total Electric Operating Revenue		2,393.0		2,259.5		133.5
Regulated Gas Revenue		127.6		142.2		(14.6	)
Other Gas Revenue		71.1		35.7		35.4
Total Gas Operating Revenue		198.7		177.9		20.8
Total Power Delivery Operating Revenue	$	2,591.7	$	2,437.4	$	154.3

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

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

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is not subject to price regulation.  Work and services includes

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mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees, and collection fees.

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

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

In response to an order issued by the New Jersey Board of Public Utilities (NJBPU) regarding changes to ACE’s retail transmission rates, ACE has established deferred accounting treatment for the difference between the rates that ACE is authorized to charge its customers for the transmission of default electricity supply and the cost that ACE incurs based on FERC-approved transmission formula rates.  Under the deferral arrangement, any over or under recovery is deferred as part of Deferred Electric Service Costs pending an adjustment of retail rates in a future proceeding.  As a consequence of the order, effective January 1, 2008, ACE’s retail transmission revenue is being recorded as Default Supply Revenue, rather than as Regulated T&D Electric Revenue, thereby conforming to the practice of PHI’s other utility subsidiaries, which previously established deferred accounting treatment for any over or under recovery of retail transmission rates relative to the cost incurred based on FERC-approved transmission formula rates.  In addition, ACE’s retail transmission revenue for the period prior to January 1, 2008 has been reclassified to Default Supply Revenue in order to conform to current period presentation.

Electric Operating Revenue

Regulated T&D Electric Revenue	2008		2007		Change
Residential	$	265.2	$	260.1	$	5.1
Commercial		354.2		337.6		16.6
Industrial		13.5		12.4		1.1
Other		166.5		108.4		58.1
Total Regulated T&D Electric Revenue	$	799.4	$	718.5	$	80.9

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

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Regulated T&D Electric Sales (GWh)	2008	2007	Change
Residential	8,159	8,526	(367)
Commercial	14,038	14,033	5
Industrial	1,919	2,018	(99)
Other	126	125	1
Total Regulated T&D Electric Sales	24,242	24,702	(460)

Regulated T&D Electric Customers (in thousands)	2008		2007		Change
Residential		1,604		1,612		(8)
Commercial		195		198		(3)
Industrial		2		1		1
Other		2		2		-
Total Regulated T&D Electric Customers		1,803		1,813		(10)

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

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

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

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

Regulated T&D Electric Revenue increased by $80.9 million primarily due to the following: (i) $36.0 million increase in Other Regulated T&D Electric Revenue from the resale of energy and capacity purchased under the Panda PPA, (offset in Fuel and Purchased Energy and Other Services Cost of Sales), (ii) $18.2 million increase due to a distribution rate increase under the 2007 Maryland Rate Orders that became effective in June 2007, including a positive $5.2 million Revenue Decoupling Adjustment,  (iii) $16.1 million increase in transmission service revenue primarily due to changes in the FERC formula rates in June 2008 and 2007, (iv) $13.4 million increase due to differences in consumption among the various customer rate classes, (v) $9.9 million increase due to a District of Columbia distribution rate increase that became effective in February 2008, (vi) $3.4 million increase due to a distribution rate change as part of an increase in the New Jersey Societal Benefit Charge that became effective in June 2008 (offset in Deferred Electric Service Costs), partially offset by (vii) $10.5 million decrease due to lower weather-related sales (a 11% decrease in Heating Degree Days and a 4% decrease in Cooling Degree Days), and (viii) $5.6 million decrease due to the sale of DPL’s Virginia retail electric distribution business.

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Default Electricity Supply

Default Supply Revenue	2008		2007		Change
Residential	$	839.8	$	826.0	$	13.8
Commercial		506.6		500.6		6.0
Industrial		42.9		44.7		(1.8)
Other		173.4		137.2		36.2
Total Default Supply Revenue	$	1,562.7	$	1,508.5	$	54.2

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

Default Electricity Supply Sales (GWh)	2008		2007		Change
Residential		7,896		8,303		(407)
Commercial		4,597		4,819		(222)
Industrial		348		457		(109)
Other		50		79		(29)
Total Default Electricity Supply Sales		12,891		13,658		(767)

Default Electricity Supply Customers (in thousands)	2008		2007		Change
Residential		1,562		1,581		(19)
Commercial		166		166		-
Industrial		1		1		-
Other		2		2		-
Total Default Electricity Supply Customers		1,731		1,750		(19)

The change in the number of Default Electricity Supply customers was primarily due to the sale of DPL’s Virginia retail electric distribution business on January 2, 2008, in connection with which the purchaser assumed the associated Default Supply obligations.  This sale resulted in a decrease of approximately 19,000 residential customers and 3,000 commercial customers.

Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales, increased by $54.2 million primarily due to the following: (i) $78.9 million increase in market-based Default Electricity Supply rates, (ii) $38.3 million increase in wholesale energy revenues due to the sale in PJM RTO at higher market prices of electricity purchased from NUGs, (iii) $9.2 million increase due to differences in consumption among the various customer rate classes, partially offset by (iv) $32.6 million decrease due to lower weather-related sales (a 11% decrease in Heating Degree Days and a 4% decrease in Cooling Degree Days), (v) $25.5 million decrease primarily due to commercial and industrial customers electing to purchase an increased amount of electricity from competitive suppliers, and (vi) $14.1 million decrease due to the sale of DPL’s Virginia retail electric distribution business.

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Gas Operating Revenue

Regulated Gas Revenue	2008		2007		Change
Residential	$	77.0	$	85.1	$	(8.1)
Commercial		43.2		48.9		(5.7)
Industrial		3.4		5.2		(1.8)
Transportation and Other		4.0		3.0		1.0
Total Regulated Gas Revenue	$	127.6	$	142.2	$	(14.6)

Regulated Gas Sales (Bcf)	2008		2007		Change
Residential		4.8		5.1		(.3)
Commercial		2.9		3.2		(.3)
Industrial		.3		.5		(.2)
Transportation and Other		3.9		3.6		.3
Total Regulated Gas Sales		11.9		12.4		(.5)

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

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

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

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

Regulated Gas Revenue decreased by $14.6 million primarily due to (i) $7.2 million decrease due to Gas Cost Rate decreases effective April 2007 and November 2007 (offset in Fuel and Purchased Energy and Other Services Cost of Sales), (ii) $6.0 million decrease due to lower weather-related sales (a 9% decrease in Heating Degree Days) and (iii) $3.8 million decrease due to differences in consumption among the various customer rate classes, partially offset by (iv) $2.4 million increase due to a base rate increase effective in April 2007.

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Other Gas Revenue

Other Gas Revenue, which is substantially offset in Fuel and Purchased Energy and Other Services Cost of Sales, increased by $35.4 million primarily due to higher off-system sales of which (i) $19.4 million was attributable to an increase in market prices, and (ii) $15.8 million was attributable to an increase in demand from electric generators and gas marketers that DPL was able to fulfill due to available pipeline capacity.  Higher available capacity resulted from lower demand for natural gas from regulated customers caused by warmer weather than 2007.

Competitive Energy Businesses

Conectiv Energy

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

Operating Revenues of the Conectiv Energy segment are derived primarily from the sale of electricity.  The primary components of its Costs of Sales are fuel and purchased power.  Because fuel and electricity prices tend to move in tandem, price changes in these commodities from period to period can have a significant impact on Operating Revenue and Costs of Sales without signifying any change in the performance of the Conectiv Energy segment.  Conectiv Energy also uses a number of and various types of derivative contracts to lock in sales margins, and to economically hedge its power and fuel purchases and sales.  Gains and losses on derivative contracts are netted in revenue and cost of sales as appropriate under the applicable accounting rules.  For these reasons, PHI from a managerial standpoint focuses on gross margin as a measure of performance.

Conectiv Energy Gross Margin

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

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

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Conectiv Energy Gross Margin and Operating Statistics	Six Months Ended June 30,				Change
		2008		2007
Operating Revenue ($ millions):
Merchant Generation & Load Service	$	993.9	$	475.7		$	518.2
Energy Marketing		618.5		498.6			119.9
Total Operating Revenue1	$	1,612.4	$	974.3		$	638.1
Cost of Sales ($ millions):
Merchant Generation & Load Service	$	794.0	$	360.3		$	433.7
Energy Marketing		594.9		476.0			118.9
Total Cost of Sales2	$	1,388.9	$	836.3		$	552.6
Gross Margin ($ millions):
Merchant Generation & Load Service	$	199.9	$	115.4		$	84.5
Energy Marketing		23.6		22.6			1.0
Total Gross Margin	$	223.5	$	138.0		$	85.5
Generation Fuel and Purchased Power Expenses ($ millions) 3:
Generation Fuel Expenses 4,5
Natural Gas	$	100.7	$	82.7		$	18.0
Coal		28.9		30.6			(1.7)
Oil		26.2		14.7			11.5
Other6		0.9		1.2			(.3)
Total Generation Fuel Expenses	$	156.7	$	129.2		$	27.5
Purchased Power Expenses 5	$	482.8	$	197.2		$	285.6
Statistics:
Generation Output (MWh):
Base-Load 7		933,954		1,048,388			(114,434)
Mid-Merit (Combined Cycle) 8		963,785		1,008,833			(45,048)
Mid-Merit (Oil Fired) 9		64,397		96,559			(32,162)
Peaking		45,157		16,854			28,303
Tolled Generation		35,438		19,599			15,839
Total		2,042,731		2,190,233			(147,502)
Load Service Volume (MWh) 10		5,268,368		3,619,437			1,648,931
Average Power Sales Price 11 ($/MWh):
Generation Sales 4	$	117.98	$	77.11		$	40.87
Non-Generation Sales 12	$	87.83	$	70.80		$	17.03
Total	$	95.01	$	72.58		$	22.43
Average on-peak spot power price at PJM East Hub ($/MWh) 13	$	96.77	$	71.55		$	25.22
Average around-the-clock spot power price at PJM East Hub ($/MWh) 13	$	81.31	$	60.34		$	20.97
Average spot natural gas price at market area M3 ($/MMBtu)14	$	11.13	$	8.33		$	2.80
Weather (degree days at Philadelphia Airport): 15
Heating degree days		2,732		3,012			(280)
Cooling degree days		393		398			(5)

1 Includes $195.2 million and $213.5 million of affiliate transactions for 2008 and 2007, respectively.

2 Includes $4.3 million and $4.0 million of affiliate transactions for 2008 and 2007, respectively.  Also, excludes depreciation and amortization expense of $18.4 million and $18.6 million, respectively.

3 Consists solely of Merchant Generation & Load Service expenses; does not include the cost of fuel not consumed by the power plants and intercompany tolling expenses.

4 Includes tolled generation.

5 Includes associated hedging gains and losses.

6 Includes emissions expenses, fuel additives, and other fuel-related costs.

7 Edge Moor Units 3 and 4 and Deepwater Unit 6.

8 Hay Road and Bethlehem, all units.

9 Edge Moor Unit 5 and Deepwater Unit 1.

10 Consists of all default electricity supply sales; does not include standard product hedge volumes.

11 Calculated from data reported in Conectiv Energy's Electric Quarterly Report (EQR) filed with the FERC; does not include capacity or ancillary services revenue.

12 Consists of default electricity supply sales, standard product power sales, and spot power sales other than merchant generation as reported in Conectiv Energy's EQR.

13 Source:  PJM website (www.pjm.com).

14 Source:  Average delivered natural gas price at Tetco Zone M3 as published in Gas Daily.

15 Source: National Oceanic and Atmospheric Administration National Weather Service data.

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

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

Merchant Generation & Load Service gross margin increased approximately $85 million primarily due to:

·   An increase of approximately $37 million primarily due to increased margins during the winter period due in part to the seasonal peak demand for natural gas. Margins were higher due to: (i) sales of natural gas made possible by the dual-fuel capability of the combined cycle mid-merit units (fuel switching as more fully described below); (ii) spot and short-term sales of firm natural gas, and natural gas transportation and storage rights; (iii) gains on natural gas positions used to provide economic protection for certain power positions; and, (iv) the opportunities created by the mid-merit combined cycle unit’s operating flexibility (option value). Fuel switching capability is the ability of the combined cycle mid-merit units to generate electricity utilizing either natural gas or oil, allowing the fuel not used to generate electricity to be sold, for purposes of maximizing the combined margin from the sale of electricity and excess fuel. This combination of strategies allowed Conectiv Energy to realize the upside potential of its overall portfolio during the winter period.  The magnitude of gain was due partly to significant fuel price increases in conjunction with less significant increases in power prices.

·   An increase of approximately $20 million due to higher PJM capacity prices net of capacity hedges.  This is primarily the result of the implementation by PJM of the Reliability Pricing Model (RPM) on June 1, 2007.

·   An increase of approximately $13 million due to the application of fair value accounting treatment with respect to coal contracts.

·   An increase of approximately $9 million due to the application of fair value accounting treatment with respect to price ineffectiveness on fuel and power hedges.

Pepco Energy Services

Pepco Energy Services’ operating revenue increased $219.5 million primarily due to (i) an increase of $167.0 million due to higher volumes of retail electric load served at higher prices in 2008 due to customer acquisitions, (ii) an increase of $38.0 million due to higher natural gas volumes driven by customer acquisitions and also higher prices in 2008, and (iii) an increase of $14.5 million due to more construction activities in 2008.

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Other Non-Regulated

Other Non-Regulated revenues decreased by $125.3 million from $38.4 million for the six months ended June 30, 2007 to $(86.9) million for the six months ended June 30, 2008.  As discussed in the Earnings Overview, a non-cash charge of $124.4 million was recorded in the quarter ended June 30, 2008 as a result of revised assumptions regarding the estimated timing of tax benefits from PCI’s cross-border energy lease investments.  In accordance with FSP 13-2, this charge has been recorded as a reduction to lease revenue from these transactions, which is included in Other Non-Regulated revenues.

Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2008		2007		Change
Power Delivery	$	1,663.2	$	1,572.0	$	91.2
Conectiv Energy		1,388.9		836.3		552.6
Pepco Energy Services		1,165.5		971.2		194.3
Corporate and Other		(207.6)		(217.4)		9.8
Total	$	4,010.0	$	3,162.1	$	847.9

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy, which is primarily associated with Default Electric Supply sales, increased by $91.2 million primarily due to: (i) $130.8 million increase in average energy costs, the result of new Default Electricity Supply contracts, (ii) $36.0 million increase for energy and capacity purchased under the Panda PPA (offset in Regulated T&D Electric Revenue), partially offset by (iii) $36.2 million decrease due to lower weather-related sales, (iv) $22.5 million decrease due to the sale of DPL’s Virginia retail electric distribution business including Default Supply obligations on January 2, 2008, (v) $9.3 million decrease due to net under-recovery of electricity supply costs resulting in an increase in the Deferred Electricity Supply deferral balance, and (vi) $8.7 million decrease due to a lower level of over-recovery of natural gas supply costs resulting in a reduction in the Deferred Gas Fuel deferral balance.  Fuel and Purchased Energy expense is substantially offset in Default Supply Revenue, Regulated Gas Revenue, and Other Gas Revenue.

Competitive Energy Business

Conectiv Energy

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."

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Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales increased $194.3 million primarily due to (i) an increase of $142.5 million due to higher volumes of purchased electricity at higher prices in 2008 to serve increased retail customer load, (ii) an increase of $42.6 million due to higher volumes of natural gas purchased at higher prices in 2008 to serve increased retail customer load, and (iii) an increase of $9.1 million due to increased construction activities in 2008.

Other Operation and Maintenance

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

	2008		2007		Change
Power Delivery	$	343.9	$	318.1	$	25.8
Conectiv Energy		75.5		68.1		7.4
Pepco Energy Services		39.9		35.5		4.4
Other Non-Regulated		.9		2.5		(1.6)
Corporate and Other		(10.6)		(6.3)		(4.3)
Total	$	449.6	$	417.9	$	31.7

Other Operation and Maintenance expenses of the Power Delivery segment increased by $25.8 million; however, excluding a favorable variance of $3.4 million primarily resulting from ACE’s sale of the B.L. England electric generating facility in February 2007, Other Operation and Maintenance expense increased by $29.2 million.  The $29.2 million increase was primarily due to (i) $9.0 million increase in preventative maintenance and system operation costs, (ii) $8.7 million increase in costs associated with Default Electricity Supply primarily due to net over-recovery of bad debt expenses (substantially offset in Default Supply Revenue), (iii) $3.9 million increase due to higher bad debt expenses (partially offset in Deferred Electric Services Costs), (iv) $3.4 million increase primarily due to recovery of stranded costs in 2007, (v) $3.2 million increase in legal expenses, (vi) $2.9 million increase in employee-related costs primarily related to updated assumptions underlying pension and other post-employment benefit liabilities, (vii) $2.3 million increase in customer service operation expenses, (viii) $1.4 million increase in Demand Side Management program costs (offset in Deferred Electric Service Costs), partially offset by (ix) $6.0 million decrease in regulatory expenses, and (x) $3.0 million decrease due to various construction project write-offs in 2007 related to customer requested work.

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

Depreciation and Amortization

Depreciation and amortization expenses decreased by $2.2 million to $183.6 million in 2008 from $185.8 million in 2007.  The decrease is primarily due to (i) $17.2 million decrease in depreciation due to a change in depreciation rates in accordance with the 2007 Maryland Rate Orders, partially offset by (ii) $13.6 million increase in amortization related to a rate increase in October 2007 for Transition Bond Charge revenue (offset in Default Supply Revenue).

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Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, decreased by $10.1 million to an expense of $8.0 million in 2008 from an expense of $18.1 million in 2007.  The decrease was primarily due to (i) $43.1 million net under-recovery associated with deferred energy costs, and (ii) $5.8 million net under- recovery associated with deferred transmission expenses, partially offset by (iii) $40.0 million net over-recovery associated with non-utility generating contracts between ACE and unaffiliated third parties.

Income Tax Expense

PHI’s effective tax rates for the six months ended June 30, 2008 and 2007 were 41.4% and 35.5%, respectively.  The increase in the effective tax rate was primarily driven by limited state tax benefits related to the charge taken on the cross-border energy lease investments as further discussed in Note (2) and Note (13).  In addition, the change in the rate was affected by a substantial increase in interest on uncertain tax positions related to the cross-border energy lease investments and certain prior period adjustments for Pepco.  These changes were offset by interest benefits related to uncertain tax positions recorded for the tentative settlement with the IRS on the mixed service cost issue (as further discussed below and in Note (13)) casualty loss deduction claims filed with the IRS in March 2008 and the June 2008 receipt of interest of $3.5 million ($2.2 million after-tax) from the state of Maryland with respect to a tax refund received during the third quarter of 2007.

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

CAPITAL RESOURCES AND LIQUIDITY

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

Working Capital

At June 30, 2008, Pepco Holdings’ current assets on a consolidated basis totaled $3.0 billion and its current liabilities totaled $2.4 billion.  At December 31, 2007, Pepco Holdings’ current assets totaled $2.0 billion and its current liabilities totaled $2.0 billion.  The increase in working capital from December 31, 2007 to June 30, 2008 is primarily due to the proceeds from long-term debt issuances in March 2008 and an increase in unrealized gains from derivative contracts.

At June 30, 2008, Pepco Holdings’ cash and current cash equivalents and its current restricted cash (cash that is available to be used only for designated purposes) totaled $354.1 million.  At December 31, 2007, Pepco Holdings’ cash and current cash equivalents and its current restricted cash totaled $69.6 million.  See “Capital Requirements — Contractual

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Arrangements with Credit Rating Triggers or Margining Rights” herein for additional information.

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

	As of June 30, 2008
	(Millions of dollars)
Type	PHI Parent	Pepco	DPL	ACE	ACE Funding	Conectiv Energy	Pepco Energy Services	PCI	Conectiv	PHI Consolidated
Variable Rate   Demand Bonds	$      -	$       -	$104.8	$   4.8	$      -	$      -	$24.3	$      -	$      -	$133.9
Bonds held under   Standby Bond   Purchase Agreement	-	-	-	17.8	-	-	-	-	-	17.8
Commercial Paper	-	-	-	107.0	-	-	-	-	-	107.0
Bank Loans	-	50.0	-	-	-	-	-	-	-	50.0
Total Short-Term Debt	$      -	$ 50.0	$104.8	$129.6	$      -	$      -	$24.3	$      -	$      -	$308.7
Current Maturities   of Long-Term Debt   and Project Funding
	$      -	$100.0	$  18.2	$       -	$ 31.4	$      -	$  9.2	$92.0	$      -	$250.8

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

Financing Activity During the Three Months Ended June 30, 2008

In April 2008, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $5.1 million on Series 2002-1 Bonds, Class A-1 and $2.1 million on Series 2003-1.

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

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

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

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

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During the first quarter of 2008, PHI subsidiaries purchased at par an aggregate principal of $82.75 million of insured tax-exempt auction rate bonds issued by municipal authorities for the benefit of the respective PHI subsidiaries.  These purchases were made in response to disruption in the market for municipal auction rate securities that made it difficult for the remarketing agent to successfully remarket the bonds.  During the second quarter of 2008, PHI subsidiaries purchased at par additional insured tax-exempt auction rate bonds in the aggregate principal amount of $174.8 million as follows:

·   In April 2008, Pepco purchased $109.5 million of Pollution Control Revenue Refunding Bonds Series 2006 due 2022 issued by the Maryland Economic Development Corporation.

·   In April 2008, ACE purchased the following series of bonds: (i) $23.15 million of Pollution Control Revenue Refunding Bonds Series 2004A due 2029 issued by Salem County and (ii) $6.5 million of Pollution Control Revenue Refunding Bonds Series 2004B due 2029 issued by Cape May County.

·   In April 2008, DPL purchased the following series of bonds issued by the Delaware Economic Development Authority: (i) $20 million of Exempt Facilities Refunding Revenue Bonds 2001A Series due 2031, (ii) $4.5 million of Exempt Facilities Refunding Revenue Bonds 2001B Series due 2031, and (iii) $11.15 million of Exempt Facilities Refunding Revenue Bonds 2000A Series due 2030.

These bonds are considered to be extinguished for accounting purposes; however each of the companies intends to hold the bonds, while monitoring the market and evaluating the options for remarketing the bonds to the public at some time in the future.

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

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

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

The payment for these VRDBs was financed by The Bank of New Yorkunder Standby Bond Purchase Agreements (SBPAs) for the respective series. If these VRDBs cannot be remarketed by the remarketing agent prior to the first anniversary of the purchase of the VRDBs by the bond trustee, ACE will be obligated to redeem 1/10th of the principal amount of each series of VRDBs held by the bond trustee every six months thereafter.  While the VRDBs are held by the bond trustee, ACE is obligated to pay interest on such bonds at a rate equal to the prime rate or Libor plus 50 basis points.

During the second quarter of 2008, ACE redeemed at maturity the following Medium Term Notes:

·   In April 2008, $1 million of 6.77% Medium Term Notes.

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·   In May 2008, (i) $21 million of 6.75% Medium Term Notes and (ii) $4 million of 6.73% Medium Term Notes.

·   In June 2008, (i) $4 million of 6.73% Medium Term Notes and (ii) $5 million of 6.71% Medium Term Notes.

Financing Activity Subsequent to June 30, 2008

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

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

·   In July 2008, $3.8 million of Pollution Control Revenue Refunding Bonds Series 1997A issued by Salem County for the benefit of ACE were tendered for purchase at par.  The purchase of these VRDBs was financed by the SBPA relating to the series.

Cash Flow Activity

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

	Cash Source / (Use)
		2008		2007
		(Millions of dollars)
Operating activities	$	693.3	$	314.8
Investing activities		(360.6)		(272.6)
Financing activities		(96.4)		(68.0)
Net increase in cash and cash equivalents	$	236.3	$	(25.8)

Operating Activities

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

	Cash Source / (Use)
		2008		2007
		(Millions of dollars)
Net income	$	114.2	$	108.8
Non-cash adjustments to net income		266.4		240.6
Changes in working capital		312.7		(34.6)
Net cash from operating activities	$	693.3	$	314.8

Net cash from operating activities was $378.5 million higher for the six months ended June 30, 2008, compared to the same period in 2007.  In addition to the increase in net income, changes in working capital increased $347.3 million primarily due to the change in cash

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collateral requirements associated with Competitive Energy activities.  Cash collateral requirements may fluctuate significantly based on changing energy market prices.

Investing Activities

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

	Cash (Use) / Source
		2008		2007
		(Millions of dollars)
Construction expenditures	$	(365.8)	$	(285.0)
Cash proceeds from sale of other assets		51.2		10.6
Changes in restricted cash		(48.2)		(.9)
All other investing cash flows, net		2.2		2.7
Net cash used by investing activities	$	(360.6)	$	(272.6)

Net cash used by investing activities increased $88.0 million for the six months ended June 30, 2008 compared to the same period in 2007.  The increase was due in part to: (i) $80.8 million increase in capital expenditures of which $39.4 million was attributable to Conectiv Energy and $26.3 million was attributable to Power Delivery and (ii) $47.3 million increase in the use of restricted cash, offset by (iii) an increase of $40.6 million in cash proceeds from the sale of assets. The increase in Conectiv Energy capital expenditures was primarily due to the construction of new generation plants.  The increase in Power Delivery capital expenditures was primarily attributable to capital costs associated with new customer services, distribution reliability, and transmission. The proceeds from the sale of assets in 2008 consisted primarily of $50.1 million received from DPL’s sale of its Virginia operations.  Proceeds from the sale of assets in 2007 consisted primarily of $9.0 million received from the sale of the B.L. England generating facility.  The increased use of restricted cash was the result of an increase in SOS collateral held by DPL and Pepco.

Financing Activities

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

	Cash (Use) / Source
		2008		2007
		(Millions of dollars)
Dividends paid on common and preferred stock	$	(108.6)	$	(100.5)
Common stock issued for the Dividend Reinvestment Plan		14.3		14.1
Issuance of common stock		14.6		23.9
Redemption of preferred stock of subsidiaries		-		(18.2)
Issuances of long-term debt		400.0		451.4
Reacquisition of long-term debt		(405.2)		(364.2)
Issuances (repayments) of short-term debt, net		19.9		(63.6)
All other financing cash flows, net		(31.4)		(10.9)
Net cash used by financing activities	$	(96.4)	$	(68.0)

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Net cash used by financing activities increased $28.4 million for the six months ended June 30, 2008, compared to the same period in 2007.

Changes in Outstanding Common Stock.  Proceeds from the issuance of stock decreased in the 2008 period due to a decrease in stock options exercised.  Under the Shareholder Dividend Reinvestment Plan (DRP), PHI issued 571,271 shares of common stock during the six months ended June 30, 2008, as compared to 490,713 shares issued during the six months ended June 30, 2007.  Under the Long-Term Incentive Plan (LTIP), PHI issued 548,216 shares of common stock during the six months ended June 30, 2008, and 513,602 shares of common stock during the six months ended June 30, 2007.

Common Stock Dividend.  Common stock dividend payments were $108.5 million in the first half of 2008 and $100.3 million in the first half of 2007. The increase in common dividends paid in 2008 was the result of additional shares outstanding (primarily from PHI’s sale of 6.5 million shares of common stock in November 2007) and a quarterly dividend increase from 26 cents per share to 27 cents per share beginning in the first quarter of 2008.

Changes in Outstanding Preferred Stock.  Preferred stock redemptions in 2007 consisted of DPL’s redemption in January 2007, at prices ranging from 103% to 105% of par, of the following securities, representing all of DPL’s outstanding preferred stock, at an aggregate cost of $18.9 million:

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

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

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

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

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

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

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

·   In January 2008, ACE Funding made principal payments of $5.4 million on Series 2002-1 Bonds, Class A-1 and $2.2 million on Series 2003-1.

·   In March 2008, Pepco re-opened its November 2007 issue of $250 million 6.5% senior notes due November 2037 collateralized by first mortgage bonds, and issued an additional $250 million in principal amount of senior notes, increasing the outstanding principal amount of the 6.5% senior notes due November 2037 to $500 million.

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

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

·   In March 2008, DPL purchased the following series of bonds issued by The Delaware Economic Development Authority: (i) $27.75 million of Exempt Facilities Revenue Refunding Bonds 2000B Series due 2030, (ii) $15 million of Exempt Facilities Revenue Refunding Bonds 2003A Series due 2038 and (iii) $15 million of Exempt Facilities Revenue Refunding Bonds 2002A Series due 2032.

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

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

Cash flows from the issuance and reacquisition of long-term debt in the first and second quarters of 2007 were attributable primarily to the following transactions:

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

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

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

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

·   In April 2007, PHI issued $200 million of 6.0% notes due 2019 in a private placement.  Proceeds were used to redeem, on May 31, 2007, $200 million of 5.5% notes due August 15, 2007 at a price of 100.0377% of par.

·   In April 2007, ACE retired at maturity $15 million of 7.52% medium-term notes.

·   In April 2007, ACE Funding made principal payments of $4.9 million on Series 2002-1 Transition Bonds, Class A-1 and $2.0 million on Series 2003-1 Transition Bonds, Class A-1 with a weighted average interest rate of 2.89%.

·   In May 2007, DPL retired at maturity $50 million of 8.125% medium-term notes.

·   In June 2007, PHI issued $250 million of 6.125% notes due 2017 in a public offering.  Net proceeds along with short-term debt were used to repay $300 million of 5.5% notes due August 15, 2007.

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

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

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Changes in Short-Term Debt.  In the first quarter of 2008, Pepco and DPL redeemed a total of $108.0 million in short-term debt with cash from capital contributions.  In the second quarter of 2008, Pepco incurred $50 million in short term loans, as described above under the heading “Financing Activity During the Three Months Ended June 30, 2008,” and ACE issued $78 million of commercial paper.

Capital Requirements

Capital Expenditures

Pepco Holdings' total capital expenditures for the six months ended June 30, 2008 totaled $365.8 million, of which $120.9 million was incurred by Pepco, $71.9 million was incurred by DPL, $88.9 million was incurred by ACE and $59.4 million was incurred by Conectiv Energy.  The remainder was incurred primarily by Pepco Energy Services.  The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability, and transmission.

In its Annual Report on Form 10-K for the year ended December 31, 2007, PHI projected the construction expenditures for its 230-mile, 500-kilovolt Mid-Atlantic Power Pathway Project (the MAPP Project) to be approximately $1 billion over a six-year period beginning in 2008.  The MAPP Project will primarily be located in the Pepco and DPL service territory.  This amount does not include the cost of significant 230 kilovolt support lines in Maryland and New Jersey to connect to the 500-kilovolt line, with an estimated cost of $200 million and the additional cost of a direct current system underwater crossing of Chesapeake Bay, at an estimated cost of $400 million.  These enhancements have been recommended to PJM, and if approved, will increase PHI’s projected costs associated with the MAPP.

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

For a discussion of PHI’s third party guarantees, indemnifications, obligations and off-balance sheet arrangements, see Note (13) “Commitments and Contingencies” to the Consolidated Financial Statements of PHI included in Part I, Item 1, in this Form 10-Q.

Dividends

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

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Energy Contract Net Asset Activity

The following table provides detail on changes in the net asset or liability position of the Competitive Energy businesses (consisting of the activities of the Conectiv Energy and Pepco Energy Services segments) with respect to energy commodity contracts.  The balances reflected in the table are stated gross, before the netting of collateral required by FIN 39-1.

Roll-forward of Fair Value Energy Contract Net Assets For the Six Months Ended June 30, 2008 (Dollars are pre-tax and in millions)
	Energy Commodity Activities (a)
Total Fair Value Energy Contract Net   Assets at December 31, 2007	$	18.1
Total change in unrealized fair value		20.8
Less:  Reclassification to realized at settlement of contracts		(68.6)
Effective portion of changes in fair value - recorded     in Other Comprehensive Income		618.2
Cash flow hedge ineffectiveness - recorded in earnings		10.3
Total Fair Value Energy Contract Net Assets at June 30, 2008	$	598.8
Detail of Fair Value Energy Contract Net Assets at June 30, 2008 (see above)
Current Assets (unrealized gains - derivative contracts)	$	652.0
Noncurrent Assets (other assets)		116.6
Total Fair Value Energy Contract Assets		768.6
Current Liabilities (other current liabilities)		126.4
Noncurrent Liabilities (other liabilities)		43.4
Total Fair Value Energy Contract Liabilities		169.8
Total Fair Value Energy Contract Net Assets	$	598.8

Notes:
(a)	Includes all Statement of Financial Accounting Standards (SFAS) No. 133 hedge activity and trading activities recorded at fair value through Accumulated Other Comprehensive Income (AOCI) or on the Statement of Earnings, as required.

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 June 30, 2008 and are subject to change as a result of changes in these factors:

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Maturity and Source of Fair Value of Energy Contract Net Assets (Liabilities) As of June 30, 2008 (Dollars are pre-tax and in millions)
	Fair Value of Contracts at June 30, 2008                           Maturities
	2008	2009	2010	2011 and  Beyond	Total Fair Value
Energy Commodity Activities, net (a)
Actively Quoted (i.e., exchange-traded) prices	$  75.6	$118.8	$42.0	$15.3	$251.7
Prices provided by other external sources (b)	224.3	80.6	37.2	.3	342.4
Modeled (c)	4.7	-	-	-	4.7
Total	$304.6	$199.4	$79.2	$15.6	$598.8

Notes:
(a)	Includes all SFAS No. 133 hedge activity and trading activities recorded at fair value through AOCI or on the Statement of Earnings, as required.
(b)	Prices provided by other external sources reflect information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(c)	Modeled values include significant inputs, usually representing more than 10% of the valuation, not readily observable in the market.

Contractual Arrangements with Credit Rating Triggers or Margining Rights

Under certain contractual arrangements entered into by PHI’s subsidiaries in connection with the Competitive Energy business and other transactions, the subsidiary may be required to provide cash collateral or letters of credit as security for its contractual obligations if the credit ratings of the subsidiary are downgraded.  In the event of a downgrade, the amount required to be posted would depend on the amount of the underlying contractual obligation existing at the time of the downgrade.  Based on contractual provisions in effect at June 30, 2008, PHI estimates that if a one-level downgrade in the credit rating of PHI and all of its affected subsidiaries were to occur, the additional aggregate cash collateral or letters of credit amount required would be $426 million for PHI and each of its relevant subsidiaries.  PHI believes that it and its utility subsidiaries maintain adequate short-term funding sources in the event the additional collateral or letters of credit are required.

Many of the contractual arrangements entered into by PHI’s subsidiaries in connection with Competitive Energy and Default Electricity Supply activities include margining rights pursuant to which the PHI subsidiary or a counterparty may request collateral if the market value of the contractual obligations reaches levels in excess of the credit thresholds established in the 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 June 30, 2008, Pepco Holdings’ subsidiaries engaged in Competitive Energy activities and Default Electricity Supply activities are holding net cash collateral in the amount of $303.4 million in connection with these activities.

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REGULATORY AND OTHER MATTERS

For a discussion of material pending matters such as regulatory and legal proceedings, and other commitments and contingencies, see Note (13) “Commitments and Contingencies” to the Consolidated Financial Statements of PHI included as Part I, Item 1 in this Form 10-Q.

CRITICAL ACCOUNTING POLICIES

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

NEW ACCOUNTING STANDARDS AND PRONOUNCEMENTS

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

FORWARD-LOOKING STATEMENTS

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

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;

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

· Weather conditions;

· Population growth rates and demographic patterns;

· Competition for retail and wholesale customers;

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

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

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

· Changes in accounting standards or practices;

· Changes in project costs;

· Unanticipated changes in operating expenses and capital expenditures;

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

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

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

· Pace of entry into new markets;

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

· Interest rate fluctuations and credit market concerns; and

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

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

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

  AND RESULTS OF OPERATIONS

POTOMAC ELECTRIC POWER COMPANY

GENERAL OVERVIEW

Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in Washington, D.C. and major portions of Montgomery County and Prince George’s County in suburban Maryland.  Pepco provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier, in both the District of Columbia and Maryland.  Default Electricity Supply is known as Standard Offer Service in both the District of Columbia and Maryland.  Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.1 million.  As of June 30, 2008, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to Washington, D.C. customers.

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

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

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RESULTS OF OPERATIONS

The accompanying results of operations discussion is for the six months ended June 30, 2008, compared to the six months ended June 30, 2007.  Other than this disclosure, information under this item has been omitted in accordance with General Instruction H to the Form 10-Q.  All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2008		2007		Change
Regulated T&D Electric Revenue	$	469.4	$	415.2	$	54.2
Default Supply Revenue		578.2		571.3		6.9
Other Electric Revenue		15.8		15.1		.7
Total Operating Revenue	$	1,063.4	$	1,001.6	$	61.8

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

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

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

Regulated T&D Electric

Regulated T&D Electric Revenue	2008		2007		Change
Residential	$	119.2	$	116.0	$	3.2
Commercial		259.0		248.2		10.8
Industrial		-		-		-
Other		91.2		51.0		40.2
Total Regulated T&D Electric Revenue	$	469.4	$	415.2	$	54.2

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

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2008		2007		Change
Residential		3,699		3,878		(179)
Commercial		9,242		9,241		1
Industrial		-		-		-
Other		78		77		1
Total Regulated T&D Electric Sales		13,019		13,196		(177)

Regulated T&D Electric Customers (in thousands)	2008		2007		Change
Residential		687		682		5
Commercial		73		74		(1)
Industrial		-		-		-
Other		-		-		-
Total Regulated T&D Electric Customers		760		756		4

Regulated T&D Electric Revenue increased by $54.2 million primarily due to the following: (i) $36.0 million increase in Other Regulated T&D Electric Revenue from the resale of energy and capacity purchased under the power purchase agreement between Panda-Brandywine, L.P. (Panda) and Pepco (the Panda PPA) (offset in Fuel and Purchased Energy), (ii) $9.9 million increase due to a District of Columbia distribution rate increase that became effective in February 2008, (iii) $8.4 million increase due to a distribution rate increase under the 2007 Maryland Rate Order that became effective in June 2007, including a positive $2.3 million Revenue Decoupling Adjustment, (iv) $5.8 million increase due to differences in consumption among the various customer rate classes,  partially offset by (v) $7.5 million decrease due to lower weather-related sales (a 16% decrease in Heating Degree Days and a 5% decrease in Cooling Degree Days).

Default Electricity Supply

Default Supply Revenue	2008		2007		Change
Residential	$	359.4	$	349.1	$	10.3
Commercial		215.1		217.5		(2.4)
Industrial		-		-		-
Other		3.7		4.7		(1.0)
Total Default Supply Revenue	$	578.2	$	571.3	$	6.9

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Default Electricity Supply Sales (GWh)	2008		2007		Change
Residential		3,505		3,684		(179)
Commercial		1,950		2,183		(233)
Industrial		-		-		-
Other		5		33		(28)
Total Default Electricity Supply Sales		5,460		5,900		(440)

Default Electricity Supply Customers (in thousands)	2008		2007		Change
Residential		655		655		-
Commercial		53		52		1
Industrial		-		-		-
Other		-		-		-
Total Default Electricity Supply Customers		708		707		1

Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy, increased by $6.9 million primarily due to the following: (i) $44.3 million increase in market-based Default Electricity Supply rates, (ii) $7.0 million increase primarily due to differences in consumption among the various customer rate classes, partially offset by (iii) $23.0 million decrease due to lower weather-related sales (a 16% decrease in Heating Degree Days and a 5% decrease in Cooling Degree Days), and (iv) $22.0 million decrease primarily due to commercial and industrial customers electing to purchase an increased amount of electricity from competitive suppliers.

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

	2008		2007
Sales to District of Columbia customers		32%		36%
Sales to Maryland customers		50%		51%

Operating Expenses

Fuel and Purchased Energy

Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply sales, increased by $40.5 million to $601.3 million in 2008 from $560.8 million in 2007.  The increase is primarily due to the following: (i) $67.2 million increase in average energy costs, the result of new Default Electricity Supply contracts, (ii) $36.0 million increase for energy and capacity purchased under the Panda PPA (offset in Regulated T&D Electric Revenue), partially offset by (iii) $24.4 million decrease due to lower weather-related sales, (iv) $19.5 million decrease primarily due to commercial customers electing to purchase an increased amount of electricity from competitive suppliers, and (v) $18.6 million decrease due to net under-recovery of electricity supply costs resulting in an increase in the Deferred Electricity Supply deferral balance.  Fuel and Purchased Energy expense is substantially offset in Default Supply Revenue.

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Other Operation and Maintenance

Other Operation and Maintenance increased by $4.7 million to $147.0 million in 2008 from $142.3 million in 2007.  The increase was primarily due to the following:  (i) $4.7 million increase in costs associated with Default Electricity Supply primarily due to net over-recovery of bad debt expenses (substantially offset in Default Supply Revenue) as further discussed below, (ii) $2.7 million increase in employee-related costs primarily related to updated assumptions underlying pension and other post-employment benefit liabilities, (iii) $1.6 million increase in preventative maintenance and system operation costs, and (iv) $.9 million increase due to higher bad debt expense, partially offset by (v) $4.7 million decrease in regulatory expenses, and (vi) $3.0 million decrease due to various construction project write-offs in 2007 related to customer requested work.

In the second quarter of 2008, Pepco recorded an adjustment to correct errors in other operation and maintenance expenses for prior periods where late payment fees were incorrectly recognized. This adjustment resulted in an increase in other operation and maintenance expenses for the three and six months ended June 30, 2008 of $3.7 million and $3.3 million, respectively. These adjustments are not considered material.

Depreciation and Amortization

Depreciation and Amortization expenses decreased by $14.7 million to $69.2 million in 2008 from $83.9 million in 2007.  The decrease was primarily due to a change in depreciation rates in accordance with the 2007 Maryland Rate Order.

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $6.2 million to a net expense of $35.9 million in 2008 from a net expense of $29.7 million in 2007.  This increase was primarily due to an increase in interest expense related to long-term debt.

Income Tax Expense

Pepco’s effective tax rates for the six months ended June 30, 2008 and 2007 were 34.4% and 40.9%, respectively.  The change in the rate primarily resulted from the June 2008 receipt of interest of $3.5 million ($2.2 million after-tax) on the Company’s state tax refund received in the third quarter of 2007, certain depreciation book/tax differences, and a reduction in previously accrued interest in the second quarter of 2008 related to the uncertain tax positions for the tentative IRS settlement on the mixed service cost issue (as further discussed in Note 10).  These benefits were offset by the recording of certain interest adjustments related to prior period uncertain tax positions as discussed below.

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

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In the second quarter of 2008, Pepco recorded certain adjustments to correct errors in the prior period FIN 48 interest calculations. These interest adjustments resulted in additional income tax expense for the six months ended June 30, 2008 of $.8 million, which is not considered material.

Capital Requirements

Capital Expenditures

Pepco's capital expenditures for the six months ended June 30, 2008, totaled $120.9 million.  These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

In its Annual Report on Form 10-K for the year ended December 31, 2007, PHI projected the construction expenditures for its 230-mile, 500-kilovolt Mid-Atlantic Power Pathway Project (the MAPP Project) to be approximately $1 billion over a six-year period beginning in 2008.  The MAPP Project will primarily be located in the Pepco and Delmarva Power & Light Company service territory.  This amount does not include the cost of significant 230 kilovolt support lines in Maryland and New Jersey to connect to the 500-kilovolt line, with an estimated cost of $200 million and the additional cost of a direct current system underwater crossing of Chesapeake Bay, at an estimated cost of $400 million.  These enhancements have been recommended to PJM, and if approved, will increase Pepco’s projected costs associated with the MAPP.

FORWARD-LOOKING STATEMENTS

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

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

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

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

· Weather conditions;

· Population growth rates and demographic patterns;

· Competition for retail and wholesale customers;

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

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

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

· Changes in project costs;

· Unanticipated changes in operating expenses and capital expenditures;

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

· Restrictions imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Council and other applicable electric reliability organizations;

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

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

· Interest rate fluctuations and credit market concerns; and

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

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

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

   AND RESULTS OF OPERATIONS

DELMARVA POWER & LIGHT COMPANY

GENERAL OVERVIEW

Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and Virginia (until the sale of its Virginia operations on January 2, 2008).  DPL provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its territories who do not elect to purchase electricity from a competitive supplier.  Default Electricity Supply is also known as Standard Offer Service in Maryland and in Delaware. DPL’s electricity distribution service territory covers approximately 5,000 square miles and has a population of approximately 1.3 million.  As of June 30, 2008, approximately 68% of delivered electricity sales were to Delaware customers and approximately 32% were to Maryland customers.  In northern Delaware, DPL also supplies and distributes natural gas to retail customers and provides transportation-only services to retail customers that purchase natural gas from other suppliers.  DPL’s natural gas distribution service territory covers approximately 275 square miles and has a population of approximately .5 million.

In January 2008, DPL completed (i) the sale of its retail electric distribution business on the Eastern Shore of Virginia to A&N Electric Cooperative (A&N) for a purchase price of approximately $48.8 million, after closing adjustments, and (ii) the sale of its wholesale electric transmission business located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase price of approximately $5.4 million, after closing adjustments.  Each of A&N and ODEC assumed certain post-closing liabilities and unknown pre-closing liabilities related to the respective assets they purchased (including, in the A&N transaction, most environmental liabilities), except that DPL remained liable for unknown pre-closing liabilities if they become known within six months after the January 2, 2008 closing date.  The allowance period for A&N and/or ODEC to notify DPL has passed and no notification was made with respect to the discovery of additional pre-closing liabilities.  A&N has delayed final payment of approximately $3.5 million due to a dispute in the final true-up amounts.  DPL is in discussions with A&N to resolve the issues.  DPL can not predict the outcome of these discussions.  These sales resulted in a $3.1 million pre-tax gain ($1.8 million after-tax), which was recorded during the first quarter of 2008.  In connection with the sales, A&N assumed on the sale date DPL’s obligation to provide Default Electricity Supply (which in Virginia is referred to as Default Supply) to customers in DPL’s former Virginia service territory.

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

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revenue.  As a consequence, the only factors that will cause distribution revenue to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer.

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

RESULTS OF OPERATIONS

The accompanying results of operations discussion is for the six months ended June 30, 2008, compared to the six months ended June 30, 2007.  Other than this disclosure, information under this item has been omitted in accordance with General Instruction H to the Form 10-Q.  All amounts in the tables (except sales and customers) are in millions of dollars.

Electric Operating Revenue

		2008		2007	Change
Regulated T&D Electric Revenue	$	172.6	$	157.6	$	15.0
Default Supply Revenue		401.0		405.8		(4.8)
Other Electric Revenue		9.8		10.3		(.5)
Total Electric Operating Revenue	$	583.4	$	573.7	$	9.7

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

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

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

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

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Regulated T&D Electric

Regulated T&D Electric Revenue		2008		2007	Change
Residential	$	80.2	$	78.8	$	1.4
Commercial		46.2		43.3		2.9
Industrial		5.9		5.7		.2
Other		40.3		29.8		10.5
Total Regulated T&D Electric Revenue	$	172.6	$	157.6	$	15.0

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2008	2007	Change
Residential	2,474	2,628		(154)
Commercial	2,606	2,653		(47)
Industrial	1,344	1,436		(92)
Other	25	26		(1)
Total Regulated T&D Electric Sales	6,449	6,743		(294)

Regulated T&D Electric Customers (in thousands)	2008	2007	Change
Residential	437	453		(16)
Commercial	58	61		(3)
Industrial	1	-		1
Other	1	1		-
Total Regulated T&D Electric Customers	497	515		(18)

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

Regulated T&D Electric Revenue increased by $15.0 million primarily due to the following: (i) $9.8 million increase due to a distribution rate increase under the 2007 Maryland Rate Order that became effective in June 2007, including a positive $2.9 million Revenue Decoupling Adjustment, (ii) $7.2 million increase in transmission service revenues primarily due to changes in Federal Energy Regulatory Commission formula rates in June 2008 and 2007, (iii) $6.0 million increase due to differences in consumption among the various customer rate classes, partially offset by (iv) $5.6 million decrease due to the sale of the Virginia retail electric distribution business and (v) $2.4 million decrease due to lower weather-related sales (a 5% decrease in Heating Degree Days and a 12% decrease in Cooling Degree Days).

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Default Electricity Supply

Default Supply Revenue		2008		2007	Change
Residential	$	262.2	$	266.9	$	(4.7)
Commercial		114.2		115.1		(0.9)
Industrial		19.5		19.9		(0.4)
Other		5.1		3.9		1.2
Total Default Supply Revenue	$	401.0	$	405.8	$	(4.8)

Default Electricity Supply Sales (GWh)	2008	2007	Change
Residential	2,405	2,599		(194)
Commercial	1,093	1,078		15
Industrial	200	270		(70)
Other	22	24		(2)
Total Default Electricity Supply Sales	3,720	3,971		(251)

Default Electricity Supply Customers (in thousands)	2008	2007	Change
Residential	427	449		(22)
Commercial	49	51		(2)
Industrial	-	-		-
Other	1	1		-
Total Default Electricity Supply Customers	477	501		(24)

The change in the number of Default Electricity Supply customers was primarily due to the sale of DPL’s Virginia retail electric distribution business on January 2, 2008, in connection with which the purchaser assumed the associated Default Supply obligations.  This resulted in a decrease of approximately 19,000 residential customers and 3,000 commercial customers.

Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy, decreased by $4.8 million primarily due to the following: (i) $14.1 million decrease due to the sale of the Virginia retail electric distribution business, (ii) $7.9 million decrease due to lower weather-related sales (a 5% decrease in Heating Degree Days and a 12% decrease in Cooling Degree Days),  partially offset by (iii) $11.0 million increase in market-based Default Electricity Supply rates, and (iv) $4.2 million increase primarily due to customers electing to purchase a decreased amount of electricity from competitive suppliers.

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

	2008	2007
Sales to Delaware customers	54%	53%
Sales to Maryland customers	65%	68%
Sales to Virginia customers	-	88%

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Natural Gas Operating Revenue

	2008		2007		Change
Regulated Gas Revenue	$	127.6	$	142.2	$	(14.6)
Other Gas Revenue		71.1		35.7		35.4
Total Natural Gas Operating Revenue	$	198.7	$	177.9	$	20.8

The table above shows the amounts of Natural Gas Operating Revenue from sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue).  Regulated Gas Revenue includes the revenue DPL receives for on-system natural gas delivered sales and the transportation of natural gas for customers.  Other Gas Revenue includes off-system natural gas sales and the release of excess system capacity.

Regulated Gas Revenue	2008		2007		Change
Residential	$	77.0	$	85.1	$	(8.1)
Commercial		43.2		48.9		(5.7)
Industrial		3.4		5.2		(1.8)
Transportation and Other		4.0		3.0		1.0
Total Regulated Gas Revenue	$	127.6	$	142.2	$	(14.6)

Regulated Gas Sales (billion cubic feet)	2008		2007		Change
Residential		4.8		5.1		(.3)
Commercial		2.9		3.2		(.3)
Industrial		.3		.5		(.2)
Transportation and Other		3.9		3.6		.3
Total Regulated Gas Sales		11.9		12.4		(.5)

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

Regulated Gas Revenue

Regulated Gas Revenue decreased by $14.6 million primarily due to (i) $7.2 million decrease due to Gas Cost Rate decreases effective April 2007 and November 2007 (offset in Gas Purchased expense), (ii) $6.0 million decrease due to lower weather-related sales (a 9% decrease in Heating Degree Days), (iii) $3.8 million decrease due to differences in consumption among

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the various customer rate classes, partially offset by (iv) $2.4 million increase due to a base rate increase effective in April 2007.

Other Gas Revenue

Other Gas Revenue, which is substantially offset in Gas Purchased expense, increased by $35.4 million primarily due to higher off-system sales of which (i) $19.4 million was attributable to an increase in market prices, and (ii) $15.8 million was attributable to an increase in demand from electric generators and gas marketers that DPL was able to fulfill due to available pipeline capacity.  Higher available capacity resulted from lower demand for natural gas from regulated customers caused by warmer weather than 2007.

Operating Expenses

Fuel and Purchased Energy

Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply sales, decreased by $16.6 million to $386.7 million in 2008 from $403.3 million in 2007.  The decrease was primarily due to (i) $22.5 million decrease due to the sale of the Virginia retail electric distribution business including Default Supply obligations on January 2, 2008, (ii) $8.5 million decrease due to lower weather-related sales, partially offset by (iii) $9.3 million increase due to net over-recovery of electricity supply costs resulting in a reduction of the Deferred Electricity Supply deferral balance, (iv) $2.7 million increase in average energy costs, the result of new Default Electricity Supply contracts, and (v) $2.3 million increase due to differences in consumption among various customer rate classes.  Fuel and Purchased Energy expense is substantially offset in Default Supply Revenue.

Gas Purchased

Total Gas Purchased, which is primarily offset in Regulated Gas Revenue and Other Gas Revenue, increased by $19.4 million to $156.5 million in 2008 from $137.1 million in 2007.  The increase is primarily due to (i) $32.6 million increase in purchases for off-system sales, partially offset by (ii) $8.8 million decrease from the settlement of financial hedges (entered into as part of DPL’s regulated natural gas hedge program), and (iii) $8.7 million decrease in the deferred gas fuel balance.

Other Operation and Maintenance

Other Operation and Maintenance increased by $10.9 million to $110.3 million in 2008 from $99.4 million in 2007.  The increase was primarily due to the following:  (i) $3.8 million increase in preventative maintenance and system operation costs, (ii) $3.1 million increase in costs associated with Default Electricity Supply primarily due to lower under-recovery of bad debt expenses (substantially offset in Default Supply Revenue), (iii) $1.6 million increase due to higher bad debt expenses, and (iv) $1.4 million increase in legal expenses, partially offset by (v) $1.5 million decrease in regulatory expenses.

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Gain on Sale of Assets

Gain on Sale of Assets increased by $2.5 million to $3.1 million in 2008 from $.6 million in 2007.  The increase was primarily due to a $3.1 million gain on the sale of the Virginia retail electric distribution business on January 2, 2008.

Other Income (Expense)

Other Expenses (which are net of Other Income) decreased by $4.4 million to a net expense of $15.2 million in 2008 from a net expense of $19.6 million in 2007.  The decrease was primarily due to a decrease in interest expense on short and long term debt.

Income Tax Expense

DPL’s effective tax rates for the six months ended June 30, 2008 and 2007 were 32.6% and 34.7%, respectively.  The change in the rate resulted from a decrease in the benefit recognized on changes in estimates and interest related to uncertain and effectively settled tax positions (primarily related to the reversal of interest reserves related to a state tax position settled in 2007 partially offset by the reversal of interest reserves related to the mixed service cost issue).

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

Capital Requirements

Capital Expenditures

DPL’s capital expenditures for the six months ended June 30, 2008, totaled $71.9 million.  These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

In its Annual Report on Form 10-K for the year ended December 31, 2007, PHI projected the construction expenditures for its 230-mile, 500-kilovolt Mid-Atlantic Power Pathway Project (the MAPP Project) to be approximately $1 billion over a six-year period beginning in 2008.  The MAPP Project will primarily be located in the Potomac Electric Power Company and DPL service territory.  This amount does not include the cost of significant 230 kilovolt support lines in Maryland and New Jersey to connect to the 500-kilovolt line, with an estimated cost of $200 million and the additional cost of a direct current system underwater crossing of Chesapeake Bay, at an estimated cost of $400 million.  These enhancements have been recommended to PJM, and if approved, will increase DPL’s projected costs associated with the MAPP.

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FORWARD-LOOKING STATEMENTS

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

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

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

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

· Weather conditions;

· Population growth rates and demographic patterns;

· Competition for retail and wholesale customers;

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

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

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

· Changes in project costs;

· Unanticipated changes in operating expenses and capital expenditures;

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

· Restrictions imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Council and other applicable electric reliability organizations;

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

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

· Interest rate fluctuations and credit market concerns; and

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

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

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

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ACE

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

     AND RESULTS OF OPERATIONS

ATLANTIC CITY ELECTRIC COMPANY

GENERAL OVERVIEW

Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey.  ACE provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive supplier.  Default Electricity Supply is also known as Basic Generation Service (BGS) in New Jersey.  ACE’s service territory covers approximately 2,700 square miles and has a population of approximately 1.1 million.

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

DISCONTINUED OPERATIONS

In February 2007, ACE completed the sale of the B.L. England generating facility.  B.L. England comprised a significant component of ACE’s generation operations and its sale required discontinued operations presentation under Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long Lived Assets,” on ACE’s Consolidated Statement of Earnings for the three and six months ended June 30, 2007.

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

	For the Three Months Ended June 30, 2007		For the Six Months Ended June 30, 2007
	(Millions of dollars)
Operating Revenue	$	-	$	9.7
Income Before Income Tax Expense	$	-	$	.2
Net Income	$	-	$	.1

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RESULTS OF OPERATIONS

The accompanying results of operations discussion is for the six months ended June 30, 2008, compared to the six months ended June 30, 2007.  Other than this disclosure, information under this item has been omitted in accordance with General Instruction H to the Form 10-Q.  All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2008		2007		Change
Regulated T&D Electric Revenue	$	157.4	$	145.7	$	11.7
Default Supply Revenue		583.5		521.7		61.8
Other Electric Revenue		7.8		9.1		(1.3)
Total Operating Revenue	$	748.7	$	676.5	$	72.2

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

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

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

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

In response to an order issued by the New Jersey Board of Public Utilities (NJBPU) regarding changes to ACE’s retail transmission rates, ACE has established deferred accounting treatment for the difference between the rates that ACE is authorized to charge its customers for the transmission of default electricity supply and the cost that ACE incurs based on Federal Energy Regulatory Commission (FERC)-approved transmission formula rates.  Under the deferral arrangement, any over or under recovery is deferred as part of Deferred Electric Service costs pending an adjustment of retail rates in a future proceeding.  As a consequence of the order, effective January 1, 2008, ACE’s retail transmission revenue is being recorded as Default Supply Revenue, rather than as Regulated T&D Electric Revenue, thereby conforming to the practice of PHI’s other utility subsidiaries, which previously established deferred accounting treatment for any over or under recovery of retail transmission rates relative to the cost incurred based on FERC-approved transmission formula rates.  In addition, ACE’s retail transmission revenue for the period prior to January 1, 2008 has been reclassified to Default Supply Revenue in order to conform to current period presentation.

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Regulated T&D Electric

Regulated T&D Electric Revenue		2008		2007	Change
Residential	$	65.8	$	65.3	$	.5
Commercial		49.0		46.1		2.9
Industrial		7.6		6.7		.9
Other		35.0		27.6		7.4
Total Regulated T&D Electric Revenue	$	157.4	$	145.7	$	11.7

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

Regulated T&D Electric Sales (Gigawatt hours (GWh))	2008	2007	Change
Residential	1,986	2,020		(34)
Commercial	2,190	2,139		51
Industrial	575	582		(7)
Other	23	22		1
Total Regulated T&D Electric Sales	4,774	4,763		11

Regulated T&D Electric Customers (in thousands)	2008		2007		Change
Residential		480		477		3
Commercial		64		63		1
Industrial		1		1		-
Other		1		1		-
Total Regulated T&D Electric Customers		546		542		4

Regulated T&D Electric Revenue increased by $11.7 million primarily due to the following: (i) $7.3 million increase in transmission service revenue primarily due to changes in the FERC formula rate in June 2008 and 2007, (ii) $3.4 million increase due to a distribution rate change as part of an increase in the New Jersey Societal Benefit Charge that became effective in June 2008 (offset in Deferred Electric Service Costs) and (iii) $1.6 million increase due to differences in consumption among the various customer rate classes.

Default Electricity Supply

Default Supply Revenue	2008		2007		Change
Residential	$	218.2	$	210.0	$	8.2
Commercial		177.3		168.0		9.3
Industrial		23.4		24.8		(1.4)
Other		164.6		118.9		45.7
Total Default Supply Revenue	$	583.5	$	521.7	$	61.8

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

Default Electricity Supply Sales (GWh)	2008	2007	Change
Residential	1,986	2,020	(34)
Commercial	1,554	1,558	(4)
Industrial	148	187	(39)
Other	23	22	1
Total Default Electricity Supply Sales	3,711	3,787	(76)

Default Electricity Supply Customers (in thousands)	2008		2007		Change
Residential		480		477		3
Commercial		64		63		1
Industrial		1		1		-
Other		1		1		-
Total Default Electricity Supply Customers		546		542		4

Default Supply Revenue, which is substantially offset in Fuel and Purchased Energy and Deferred Electric Service Costs, increased by $61.8 million primarily due to the following: (i) $46.1 million increase in wholesale energy revenues due to sale in PJM RTO at higher market prices of electricity purchased from NUGs, (ii) $23.6 million increase in market-based Default Electricity Supply rates, partially offset by (iii) $7.7 million decrease primarily due to customers electing to purchase an increased amount of electricity from competitive suppliers, and (iv) $1.7 million decrease due to lower weather-related sales (a 8% decrease in Heating Degree Days and a 13% increase in Cooling Degree Days).

For the six months ended June 30, 2008 and 2007, the percentage of ACE’s total sales that are derived from customers receiving Default Electricity Supply are 78% and 80%, respectively.

Operating Expenses

Fuel and Purchased Energy

Fuel and Purchased Energy, which is primarily associated with Default Electricity Supply sales, increased by $51.9 million to $518.7 million in 2008 from $466.8 in 2007.  The increase was primarily due to the following: (i) $60.8 million increase due to new annual BGS supply contracts, partially offset by (ii) $5.6 million decrease primarily due to differences in consumption among various customer rate classes, and (iii) $3.3 million decrease due to lower weather-related sales.  Fuel and Purchased Energy expense is substantially offset in Default Supply Revenue.

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Other Operation and Maintenance

Other Operation and Maintenance increased by $12.1 million to $89.0 million in 2008 from $76.9 million in 2007.  The increase was primarily due to the following:  (i) $3.4 million increase primarily due to recovery of stranded costs in 2007, (ii) $3.4 million increase in preventative maintenance and system operation costs, (iii) $1.4 million increase in Demand Side Management program costs (offset in Deferred Electric Service Costs), (iv) $1.4 million increase due to higher bad debt expenses (offset in Deferred Electric Service Costs), and (v) $1.2 million increase in legal expenses.

Depreciation and Amortization

Depreciation and Amortization expenses increased by $14.7 million to $49.2 million in 2008 from $34.5 million in 2007.  The increase is primarily due to higher amortization related to a rate increase in October 2007 for Transition Bond Charge revenue (offset in Default Supply Revenue).

Deferred Electric Service Costs

Deferred Electric Service Costs decreased by $8.0 million to an expense of $8.0 million in 2008 from an expense of $16.0 million in 2007.  The decrease was primarily due to (i) $43.1 million net under-recovery associated with deferred energy costs, and (ii) $5.8 million net under-recovery associated with deferred transmission expenses, partially offset by (iii) $40.0 million net over-recovery associated with non-utility generating contracts between ACE and unaffiliated third parties.

Income Tax Expense

ACE’s effective tax rates for the six months ended June 30, 2008 and 2007 were 26.4% and 39.1%, respectively.  The change in the rate resulted from an increase in the change in estimates and interest related to uncertain and effectively settled tax positions (primarily related to a claim made for repair costs on prior year returns), and certain depreciation life and method book/tax differences.

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

Capital Requirements

Capital Expenditures

ACE's capital expenditures for the six months ended June 30, 2008, totaled $88.9 million.  These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

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FORWARD-LOOKING STATEMENTS

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

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

· 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;

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· Restrictions imposed by federal and/or state regulatory commissions, PJM, the North American Electric Reliability Council and other applicable electric reliability organizations;

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

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

· Interest rate fluctuations and credit market concerns; and

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

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

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

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Item 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Pepco Holdings, Inc.

Commodity Price Risk

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

PHI’s risk management policies place oversight at the senior management level through the Corporate Risk Management Committee which has the responsibility for establishing corporate compliance requirements for the Competitive Energy businesses’ energy market participation.  PHI collectively refers to these energy market activities, including its commodity risk management activities, as “energy commodity” activities.  PHI uses a value-at-risk (VaR) model to assess the market risk of its Competitive Energy segments’ energy commodity activities.  PHI also uses other measures to limit and monitor risk in its commodity activities, including limits on the nominal size of positions and periodic loss limits.  VaR represents the potential fair value loss on energy contracts or portfolios due to changes in market prices for a specified time period and confidence level.  PHI estimates VaR using a delta-normal variance / covariance model with a 95 percent, one-tailed confidence level and assuming a one-day holding period.  Since VaR is an estimate, it is not necessarily indicative of actual results that may occur.

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Value at Risk Associated with Energy Contracts For the Six Months Ended June 30, 2008 (Millions of dollars)
	VaR for Competitive Energy Activity (a)
95% confidence level, one-day holding period, one-tailed
Period end	$	5.3
Average for the period	$	6.0
High	$	11.3
Low	$	3.7

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

Conectiv Energy economically hedges both the estimated plant output and fuel requirements as the estimated levels of output and fuel needs change.  Economic hedge percentages include the estimated electricity output of Conectiv Energy’s generation plants and any associated financial or physical commodity contracts (including derivative contracts that are classified as cash flow hedges under SFAS No. 133, other derivative instruments, wholesale normal purchase and sales contracts, and default electricity supply contracts).

Conectiv Energy maintains a forward 36 month program with targeted ranges for economically hedging its projected plant output combined with its energy purchase commitments.  Beginning in 2008, Conectiv Energy changed its disclosure to show the percentage of its entire expected plant output and energy purchase commitments for all hours that are hedged, as opposed to its hedged position with respect to its projected on-peak plant output and on-peak energy commitments, which previously was disclosed.  This change was made in recognition of the significant quantity of projected off-peak plant output and purchase commitments and due to the increased volatility of power prices during off-peak hours. Also beginning in 2008, Conectiv Energy is including default electricity supply contracts and associated hedges in ISONE.  The hedge percentages for all expected plant output and purchase commitment (based on the then current forward electricity price curve) are as follows:

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

The primary purpose of the risk management program is to improve the predictability and stability of margins by selling forward a portion of 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.

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As of June 30, 2008, the electricity sold forward by Conectiv Energy as a percentage of projected plant output combined with energy purchase commitments was 108%, 100%, and 67% for the 1-12 month, 13-24 month and 25-36 month forward periods, respectively.  Hedge percentages were above the target ranges due to Conectiv Energy’s success in the default electricity supply auctions and decreases in projected plant output since the forward sale commitments were entered into.  The amount of forward sales during the 1-12 month period represents 14% of Conectiv Energy’s combined total generating capability and energy purchase commitments.  The volumetric percentages for the forward periods can vary and may not represent the amount of expected value hedged.

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

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

Credit and Nonperformance Risk

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

Schedule of Credit Risk Exposure on Competitive Wholesale Energy Contracts (Millions of dollars)
	June 30, 2008
Rating (a)	Exposure Before Credit Collateral (b)	Credit Collateral (c)	Net Exposure	Number of Counterparties Greater Than10% (d)	Net Exposure of Counterparties Greater Than 10%
Investment Grade	$1,038.8	$575.5	$463.3	-	$     -
Non-Investment Grade	86.6	-	86.6	1	80.6
No External Ratings	152.5	11.3	141.2	-	-
Credit reserves			1.4

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

182

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

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

Item 4.  CONTROLS AND PROCEDURES

Pepco Holdings, Inc.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, Pepco Holdings has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of June 30, 2008 and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco Holdings have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to Pepco Holdings and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended (the Exchange Act) (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended June 30, 2008, there was no change in Pepco Holdings’ internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pepco Holdings’ internal controls over financial reporting.

Item 4T.  CONTROLS AND PROCEDURES

Potomac Electric Power Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, Pepco has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of June 30, 2008, and, based upon this evaluation, the chief executive officer and the chief financial officer of Pepco have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to Pepco that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and

183

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 June 30, 2008, there was no change in Pepco’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pepco’s internal controls over financial reporting.

Delmarva Power & Light Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, DPL has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of June 30, 2008, and, based upon this evaluation, the chief executive officer and the chief financial officer of DPL have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to DPL that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended June 30, 2008, there was no change in DPL’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, DPL’s internal controls over financial reporting.

Atlantic City Electric Company

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision, and with the participation of management, including the chief executive officer and the chief financial officer, ACE has evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of June 30, 2008, and, based upon this evaluation, the chief executive officer and the chief financial officer of ACE have concluded that these controls and procedures are effective to provide reasonable assurance that material information relating to ACE and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended June 30, 2008, there was no change in ACE’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, ACE’s internal controls over financial reporting.

184

Part II    OTHER INFORMATION

Item 1.   LEGAL PROCEEDINGS

Pepco Holdings

Other than ordinary routine litigation incidental to its and its subsidiaries’ business, PHI and its subsidiaries are not a party to, and its subsidiaries’ property is not subject to, any material pending legal proceedings except as described in Note (13), “Commitments and Contingencies—Legal Proceedings,” to the consolidated financial statements of PHI included herein.

Pepco

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

DPL

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

ACE

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

Item 1A.   RISK FACTORS

Pepco Holdings

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

The IRS challenge to cross-border energy sale and lease-back transactions entered into by a PHI subsidiary could result in loss of prior and future tax benefits.

PCI maintains a portfolio of eight cross-border energy lease investments, which as of June 30, 2008, had a equity value of approximately $1.3 billion and from which PHI historically has derived approximately $74 million per year in tax benefits in the form of interest and depreciation deductions in excess of rental income (reflecting 100% of the tax benefits).  On February 11, 2005, the Treasury Department and IRS issued a notice informing taxpayers that the IRS intends to challenge the tax benefits claimed by taxpayers with respect to certain of these investments.

185

As part of the normal PHI tax audit for 2001 and 2002, the IRS disallowed the tax benefits claimed by PHI with respect to six of the eight leases for those years.  The tax benefits claimed by PHI with respect to these leases from 2001 through December 31, 2007 were approximately $458 million. PHI has filed a protest against the IRS adjustments and the unresolved audit has been forwarded to the IRS Appeals Office.  While the audits of PHI’s federal income tax returns for subsequent tax years are ongoing or have not yet commenced, PHI anticipates that the IRS will take the same position with respect to each of the subsequent years on all eight of its cross-border energy lease investments.  If the IRS prevails, PHI would be subject to additional taxes, along with interest and possibly penalties on the additional taxes, which could have a material adverse effect on PHI’s results of operations and cash flows.  See further discussion about “Change in Accounting Estimate,” in Note (2), “Leasing Activities” in Note (5),  “Income Taxes” in Note (9)  and “Commitments and Contingencies—Regulatory and Other Matters—PHI’s Cross-Border Energy Lease Investments,” in Note (13) to the consolidated financial statements of PHI set forth in item 1 of this Form 10-Q

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

In February 2006, PHI paid approximately $121 million of taxes to cover the amount of additional taxes and interest that management estimated to be payable for the years 2001 through 2004 based on the method of tax accounting that PHI, pursuant to the proposed regulations, adopted on its 2005 tax return.  In June 2008, PHI received from the Appeals Office an offer of settlement pertaining to each of Pepco, DPL and ACE for the tax years 2001 through 2004.  PHI is substantially in agreement with this proposed settlement.  Based on the terms of the proposal, PHI expects the final settlement amount to be less than the $121 million previously deposited.  Accordingly, in the quarter ended June 30, 2008, PHI recorded after-tax interest income of $7.2million and reduced unrecognized tax benefits by a net of $18.7 million.

Pepco

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

DPL

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

ACE

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

186

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.

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

Pepco Holdings

(a) The Annual Meeting of Shareholders was held on May 16, 2008.

(b) Directors who were elected at the annual meeting:

For Term Expiring in 2009:
Jack B. Dunn IV	Votes cast for: Votes withheld:	160,583,321 5,392,516
Terence C. Golden	Votes cast for: Votes withheld:	161,753,836 4,222,001
Frank O. Heintz	Votes cast for: Votes withheld:	161,125,890 4,849,947
Barbara J. Krumsiek	Votes cast for: Votes withheld:	161,679,148 4,296,690
George F. MacCormack	Votes cast for: Votes withheld:	161,817,132 4,158,705
Richard B. McGlynn	Votes cast for: Votes withheld:	161,008,227 4,967,610
Lawrence C. Nussdorf	Votes cast for: Votes withheld:	161,073,443 4,902,395
Frank K. Ross	Votes cast for: Votes withheld:	161,005,308 4,970,529
Pauline A. Schneider	Votes cast for: Votes withheld:	108,918,648 57,057,190

187

Lester P. Silverman	Votes cast for: Votes withheld:	161,702,897 4,272,940
William T. Torgerson	Votes cast for: Votes withheld:	161,750,766 4,225,071
Dennis R. Wraase	Votes cast for: Votes withheld:	160,988,461 4,987,376

(c) The following proposal was voted on at the meeting:

The Board of Directors approved and submitted to a vote of the shareholders a proposal to ratify the appointment of PricewaterhouseCoopers LLP as independent registered public accounting firm of PHI for 2008.

This proposal passed.  The number of shares present and entitled to vote on the proposal was 165,975,838.  Adoption of the proposal required the affirmative vote of the holders of a majority of the shares of Pepco Holdings Common Stock present and entitled to vote or 82,987,920 shares.  162,721,187 shares were voted for the proposal, 1,066,887 shares were voted against the proposal, 2,187,764 shares abstained and there were no broker non-votes.

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.

188

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
10.1	PHI	Employment Agreement of Joseph M. Rigby	Exhibit 10.1 to PHI’s Form 8-K, 7/30/08
10.2	PHI	2008 Amendment to Employment Agreement of Dennis R. Wraase	Exhibit 10.2 to PHI’s Form 8-K, 7/30/08
12.1	PHI	Statements Re: Computation of Ratios	Filed herewith.
12.2	Pepco	Statements Re: Computation of Ratios	Filed herewith.
12.3	DPL	Statements Re: Computation of Ratios	Filed herewith.
12.4	ACE	Statements Re: Computation of Ratios	Filed herewith.
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.

189

Exhibit 12.1  Statements Re. Computation of Ratios

Pepco Holdings, Inc.

			For the Year Ended December 31,
	Six Months Ended  June 30, 2008			2007	2006		2005		2004		2003
	(Millions of dollars)
Income before extraordinary item (a)	$	116.2	$	324.1	$	245.0	$	368.5	$	257.4	$	204.9
Income tax expense (b)		80.8		187.9		161.4		255.2		167.3		62.1
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense		165.9		348.4		342.8		341.4		376.2		385.9
Other interest		12.4		25.4		18.8		20.3		20.6		21.7
Preferred dividend requirements     of subsidiaries		.1		.3		1.2		2.5		2.8		13.9
Total fixed charges		178.4		374.1		362.8		364.2		399.6		421.5
Non-utility capitalized interest		(2.1)		(1.6)		(1.0)		(.5)		(.1)		(10.2)
Income before extraordinary   item, income tax expense,   and fixed charges	$	373.3	$	884.5	$	768.2	$	987.4	$	824.2	$	678.3
Total fixed charges, shown above		178.4		374.1		362.8		364.2		399.6		421.5
Increase preferred stock dividend   requirements of subsidiaries to   a pre-tax amount		.1		.2		.8		1.7		1.8		4.2
Fixed charges for ratio   computation	$	178.5	$	374.3	$	363.6	$	365.9	$	401.4	$	425.7
Ratio of earnings to fixed charges   and preferred dividends		2.09		2.36		2.11		2.70		2.05		1.59

(a) Excludes income/losses from equity investments.

(b) Concurrent with the adoption of FIN 48 on January 1,  2007, amount includes interest on tax positions.

190

Exhibit 12.2  Statements Re. Computation of Ratios

 Potomac Electric Power Company

			For the Year Ended December 31,
	Six Months Ended June 30, 2008			2007	2006		2005		2004		2003
	(Millions of dollars)
Net income	$	46.6	$	125.1	$	85.4	$	165.0	$	96.5	$	103.2
Income tax expense (a)		24.4		62.3		57.4		127.6		55.7		67.3
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense		47.6		86.5		77.1		82.8		82.5		83.8
Other interest		5.7		11.6		12.9		13.6		14.3		16.2
Preferred dividend requirements     of a subsidiary trust		-		-		-		-		-		4.6
Total fixed charges		53.3		98.1		90.0		96.4		96.8		104.6
Non-utility capitalized interest		-		-		-		-		-		-
Income before income tax expense,   and fixed charges	$	124.3	$	285.5	$	232.8	$	389.0	$	249.0	$	275.1
Ratio of earnings to fixed charges		2.33		2.91		2.59		4.04		2.57		2.63
Total fixed charges, shown above		53.3		98.1		90.0		96.4		96.8		104.6
Preferred dividend requirements,   excluding mandatorily redeemable   preferred securities subsequent to   SFAS No. 150 implementation,   adjusted to a pre-tax amount		-		-		1.7		2.3		1.6		5.5
Total fixed charges and   preferred dividends	$	53.3	$	98.1	$	91.7	$	98.7	$	98.4	$	110.1
Ratio of earnings to fixed charges   and preferred dividends		2.33		2.91		2.54		3.94		2.53		2.50

(a)           Concurrent with the adoption of FIN 48 on January 1, 2007, amount includes interest on tax positions.

191

Exhibit 12.3  Statements Re. Computation of Ratios

Delmarva Power & Light Company

			For the Year Ended December 31,
	Six Months Ended June 30, 2008			2007	2006		2005		2004		2003
	(Millions of dollars)
Net income	$	42.4	$	44.9	$	42.5	$	74.7	$	63.0	$	52.4
Income tax expense (a)		20.5		37.2		32.1		57.6		48.1		37.0
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense		18.7		43.8		41.3		35.3		33.0		37.2
Other interest		1.2		2.3		2.5		2.7		2.2		2.7
Preferred dividend requirements     of a subsidiary trust		-		-		-		-		-		2.8
Total fixed charges		19.9		46.1		43.8		38.0		35.2		42.7
Income before income tax expense,   and fixed charges	$	82.8	$	128.2	$	118.4	$	170.3	$	146.3	$	132.1
Ratio of earnings to fixed charges		4.16		2.78		2.70		4.48		4.16		3.09
Total fixed charges, shown above		19.9		46.1		43.8		38.0		35.2		42.7
Preferred dividend requirements,   adjusted to a pre-tax amount		-		-		1.4		1.8		1.7		1.7
Total fixed charges and   preferred dividends	$	19.9	$	46.1	$	45.2	$	39.8	$	36.9	$	44.4
Ratio of earnings to fixed charges   and preferred dividends		4.16		2.78		2.62		4.28		3.96		2.98

(a)           Concurrent with the adoption of FIN 48 on January 1, 2007, amount includes interest on  tax positions.

192

Exhibit 12.4  Statements Re. Computation of Ratios

Atlantic City Electric Company

			For the Year Ended December 31,
	Six Months Ended June 30, 2008			2007	2006		2005		2004		2003
	(Millions of dollars)
Income from continuing operations	$	32.7	$	60.0	$	60.1	$	51.1	$	58.8	$	31.6
Income tax (benefit) expense (a)		11.7		40.9		33.0		41.2		40.7		20.7
Fixed charges:
Interest on long-term debt,     amortization of discount,     premium and expense		31.0		66.0		64.9		60.1		62.2		63.7
Other interest		1.6		3.3		3.2		3.7		3.4		2.6
Preferred dividend requirements     of subsidiary trusts		-		-		-		-		-		1.8
Total fixed charges		32.6		69.3		68.1		63.8		65.6		68.1
Income before extraordinary   item, income tax expense,   and fixed charges	$	77.0	$	170.2	$	161.2	$	156.1	$	165.1	$	120.4
Ratio of earnings to fixed charges		2.36		2.46		2.37		2.45		2.52		1.77
Total fixed charges, shown above		32.6		69.3		68.1		63.8		65.6		68.1
Preferred dividend requirements   adjusted to a pre-tax amount		.1		.5		.5		.5		.5		.5
Total fixed charges and   preferred dividends	$	32.7	$	69.8	$	68.6	$	64.3	$	66.1	$	68.6
Ratio of earnings to fixed charges   and preferred dividends		2.35		2.44		2.35		2.43		2.50		1.76

(a)           Concurrent with the adoption of FIN 48 on January 1, 2007, amount includes interest on tax positions.

193

Exhibit 31.1

CERTIFICATION

I Dennis R. Wraase, certify that:

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

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

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

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

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

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

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

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

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

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

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

 Date:  August 11, 2008     /s/ D. R. WRAASE          
Dennis R. Wraase
Chairman of the Board and      Chief Executive Officer

194

Exhibit 31.2

CERTIFICATION

I, Paul H. Barry, certify that:

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

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

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

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

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

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

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

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

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

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

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

 Date:  August 11, 2008   /s/ P. H. BARRY              
Paul H. Barry
Senior Vice President and
    Chief Financial Officer

195

Exhibit 31.3

CERTIFICATION

I, Joseph M. Rigby, certify that:

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

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

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

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

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

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

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

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

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

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

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

  Date:  August 11, 2008   /s/ J. M. RIGBY                   
Joseph M. Rigby
President and Chief Executive Officer

196

Exhibit 31.4

CERTIFICATION

I, Paul H. Barry, certify that:

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

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

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

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

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

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

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

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

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

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

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

 Date:  August 11, 2008   /s/ P. H. BARRY              
Paul H. Barry
Senior Vice President and
    Chief Financial Officer

197

Exhibit 31.5

CERTIFICATION

I, Joseph M. Rigby, certify that:

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

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

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

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

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

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

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

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

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

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

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

  Date:  August 11, 2008   /s/ J. M. RIGBY                   
Joseph M. Rigby
President and Chief Executive Officer

198

Exhibit 31.6

CERTIFICATION

I, Paul H. Barry, certify that:

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

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

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

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

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

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

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

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

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

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

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

 Date:  August 11, 2008   /s/ P. H. BARRY              
Paul H. Barry
Senior Vice President and
    Chief Financial Officer

199

Exhibit 31.7

CERTIFICATION

I, Joseph M. Rigby, certify that:

1. I have reviewed this report on Form 10-Q of Atlantic City Electric Company.

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

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

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

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

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

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

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

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

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

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

  Date:  August 11, 2008   /s/ J. M. RIGBY                   
Joseph M. Rigby
President and Chief Executive Officer

200

Exhibit 31.8

CERTIFICATION

I, Paul H. Barry, certify that:

1. I have reviewed this report on Form 10-Q of Atlantic City Electric Company.

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

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

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

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

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

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

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

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

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

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

 Date:  August 11, 2008   /s/ P. H. BARRY              
Paul H. Barry
Chief Financial Officer

201

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 June 30, 2008, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Pepco Holdings, Inc.

August 11, 2008	/s/ D. R. WRAASE                   Dennis R. Wraase Chairman of gthe Board and     Chief Executive Officer
August 11, 2008	/s/ P. H. BARRY               Paul H. Barry Senior Vice President and    Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Pepco Holdings, Inc. and will be retained by Pepco Holdings, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

202

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 June 30, 2008, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Potomac Electric Power Company.

August 11, 2008	/s/ J. M. RIGBY                   Joseph M. Rigby President and Chief Executive Officer
August 11, 2008	/s/ P. H. BARRY               Paul H. Barry Senior Vice President and    Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Potomac Electric Power Company and will be retained by Potomac Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

203

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 June 30, 2008, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Delmarva Power & Light Company.

August 11, 2008	/s/ J. M. RIGBY                   Joseph M. Rigby President and Chief Executive Officer
August 11, 2008	/s/ P. H. BARRY               Paul H. Barry Senior Vice President and    Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Delmarva Power & Light Company and will be retained by Delmarva Power & Light Company and furnished to the Securities and Exchange Commission or its staff upon request.

204

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 June 30, 2008, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Atlantic City Electric Company.

August 11, 2008	/s/ J. M. RIGBY                   Joseph M. Rigby President and Chief Executive Officer
August 11, 2008	/s/ P. H. BARRY               Paul H. Barry  Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Atlantic City Electric Company and will be retained by Atlantic City Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.

205

SIGNATURES

           Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PEPCO HOLDINGS, INC. (PHI) POTOMAC ELECTRIC POWER COMPANY (Pepco) DELMARVA POWER & LIGHT COMPANY (DPL) ATLANTIC CITY ELECTRIC COMPANY (ACE)           (Registrants)
August 11, 2008	By   /s/ P. H. BARRY                              Paul H. Barry         Senior Vice President and         Chief Financial Officer,             PHI, Pepco and DPL         Chief Financial Officer, ACE

206

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

207