Pepco 10-Q 2011 Q3 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 September 30, 2011

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 500 North Wakefield Drive Newark, DE 19702 Telephone: (202)872-2000	51-0084283
001-03559	ATLANTIC CITY ELECTRIC COMPANY (ACE), a New Jersey corporation 500 North Wakefield Drive Newark, DE 19702 Telephone: (202)872-2000	21-0398280

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

	Large Accelerated Filer	Accelerated Filer	Non- Accelerated Filer	Smaller Reporting Company
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 ACEmeet 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 October 31, 2011
Pepco Holdings	226,956,398 ($.01 par value)
Pepco	100 ($.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, LLC, 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
	Forward-Looking Statements		1
PART I	FINANCIAL INFORMATION		3
Item 1.	- Financial Statements		3
Item 2.	- Management’s Discussion and Analysis of Financial Condition and Results of Operations		109
Item 3.	- Quantitative and Qualitative Disclosures About Market Risk		176
Item 4.	- Controls and Procedures		178
PART II	OTHER INFORMATION		178
Item 1.	- Legal Proceedings		178
Item 1A	- Risk Factors		179
Item 2.	- Unregistered Sales of Equity Securities and Use of Proceeds		182
Item 3.	- Defaults Upon Senior Securities		182
Item 4.	- Reserved		182
Item 5.	- Other Information		182
Item 6.	- Exhibits		184
Signatures			186

GLOSSARY OF TERMS

Term	Definition
6.125% Notes	PHI’s 6.125% Senior Notes due 2017
6.45% Notes	PHI’s 6.45% Senior Notes due 2012
7.45% Notes	PHI’s 7.45% Senior Notes due 2032
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
ADITC	Accumulated deferred investment tax credits
AMI	Advanced metering infrastructure
AOCL	Accumulated Other Comprehensive Loss
ASC	Accounting Standards Codification
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)
Bondable Transition Property	The principal and interest payments on the Transition Bonds and related taxes, expenses and fees
BSA	Bill Stabilization Adjustment
Budget Support Act	Fiscal year 2012 Budget Support Act of 2011 approved by the Council for the District of Columbia
Calpine	Calpine Corporation
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
Conectiv	Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE
CSA	Credit Support Annex
DCPSC	District of Columbia Public Service Commission
DDOE	District of Columbia Department of the Environment
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 Standard Offer Service or BGS
Default Electricity Supply Revenue	Revenue primarily from Default Electricity Supply
DOE	U.S. Department of Energy
DPL	Delmarva Power & Light Company
DPSC	Delaware Public Service Commission
EDCs	Electric distribution companies
EDIT	Excess Deferred Income Taxes
EmPower Maryland	A Maryland demand-side management program for Pepco and DPL
Energy Services	Energy savings performance contracting services provided principally to federal, state and local government customers, and designing, constructing and operating combined heat and power, and central energy plants by Pepco Energy Services
Environmental Organizations	Anacostia Riverkeeper, Inc., the Anacostia Watershed Society and the Natural Resources Defense Council, all of which filed a motion to intervene in a case filed by the DDOE in the United States District Court for the District of Columbia.
EPA	U.S Environmental Protection Agency
EPS	Earnings per share
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States of America
GCR	Gas Cost Rate
GWh	Gigawatt hour
IIP	ACE’s Infrastructure Investment Program
IRS	Internal Revenue Service

i

Term	Definition
ISDA	International Swaps and Derivatives Association
ISRA	New Jersey’s Industrial Site Recovery Act
MAPP	Mid-Atlantic Power Pathway
Market Transition Charge Tax	Revenue ACE receives and pays to ACE Funding to recover income taxes associated with Transition Bond Charge revenue
MDC	MDC Industries, Inc.
MFVRD	Modified fixed variable rate design
Mirant	Mirant Corporation
MMBtu	One Million British Thermal Units
MPSC	Maryland Public Service Commission
MSCG	Morgan Stanley Capital Group, Inc.
MWh	Megawatt hour
New Jersey Societal Benefit Charge	Charge to ACE customers, included in revenue, to recover costs associated with New Jersey Societal Benefit Programs
New Jersey Societal Benefit Programs	Various NJBPU-mandated social programs for which ACE receives revenues to recover costs
NJBPU	New Jersey Board of Public Utilities
NJDEP	New Jersey Department of Environmental Protection
Normalization provisions	Sections of the Internal Revenue Code and related regulations that dictate how excess deferred income taxes resulting from the corporate income tax rate reduction enacted by the Tax Reform Act of 1986 and accumulated deferred investment tax credits should be treated for ratemaking purposes
NPL	National Priorities List, which, among other things, serves as a guide to EPA in determining which sites warrant further investigation to assess the nature and extent of the human health and environmental risks associated with a site
NUGs	Non-utility generators
NYMEX	New York Mercantile Exchange
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 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
PUHCA 2005	Public Utility Holding Company Act of 2005
RECs	Renewable energy credits
Regulated T&D Electric Revenue	Revenue from the transmission and the distribution of electricity to PHI’s customers within its service territories at regulated rates
Reporting Company	PHI, Pepco, DPL or ACE
RI/FS	Remedial investigation and feasibility study
ROE	Return on equity
RPS	Renewable Energy Portfolio Standards
RTEP	PJM’s Regional Transmission Expansion Plan
SEC	Securities and Exchange Commission
SERP	Supplemental Executive Retirement Plan
SOCAs	Standard Offer Capacity Agreements required to be entered into by ACE pursuant to a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey

ii

Term	Definition
SOS	Standard Offer Service, how Default Electricity Supply is referred to in Delaware, the District of Columbia and Maryland
SPCC	Spill Prevention, Control, and Countermeasure plans, required pursuant to federal regulations requiring plans for facilities using oil-containing equipment in proximity to surface waters
Transition Bond Charge	Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees
Transition Bonds	Transition Bonds issued by ACE Funding
Transmission Enhancement Credits	Enhancement credits that PHI’s utility subsidiaries receive as transmission owners from PJM for approved regional transmission expansion plan costs
Treasury rate 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
VADEQ	Virginia Department of Environmental Quality
VaR	Value at Risk
VSCC	Virginia State Corporation Commission

iii

FORWARD-LOOKING STATEMENTS

Some of the statements contained in this Quarterly Report on Form 10-Q with respect to PHI, Pepco, DPL and ACE, including each of their respective subsidiaries (each, a Reporting Company) are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and Section 27A of the Securities Act of 1933, as amended, and are subject to the safe harbor created thereby and by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding the intents, beliefs and current expectations of one or more Reporting Companies. In some cases, you can identify forward-looking statements by terminology such as “may,” “might,” “will,” “should,” “could,” “expects,” “intends,” “assumes,” “seeks to,” “plans,” “anticipates,” “believes,” “projects,” “estimates,” “predicts,” “potential,” “future,” “goal,” “objective,” or “continue” or the negative of such terms or other variations thereof or comparable terminology, or by discussions of strategy that involve risks and uncertainties. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause one or more Reporting Company’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. Therefore, forward-looking statements are not guarantees or assurances of future performance, and actual results could differ materially from those indicated by the 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 each Reporting Company’s control and may cause actual results to differ materially from those contained in forward-looking statements:

• Changes in 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 transmission and distribution facilities and the recovery of purchased power expenses;

• Weather conditions affecting usage and emergency restoration costs;

• Population growth rates and changes in demographic patterns;

• Changes in customer energy demand due to conservation measures and the use of more energy-efficient products;

• General economic conditions, including the impact of an economic downturn or recession on energy usage;

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

• Changes in tax rates or policies;

• Changes in rates of inflation;

• Changes in accounting standards or practices;

• Unanticipated changes in operating expenses and capital expenditures;

• Rules and regulations imposed by, and decisions of, federal and/or state regulatory commissions, PJM Interconnection, LLC, the North American Electric Reliability Corporation and other applicable electric reliability organizations;

• Legal and administrative proceedings (whether civil or criminal) and settlements that affect a Reporting Company’s business and profitability;

• Pace of entry into new markets;

• Interest rate fluctuations and the impact of credit and capital market conditions on the ability to obtain funding on favorable terms; and

• Effects of geopolitical events, including the threat of domestic terrorism or cyber attacks.

1

These forward-looking statements are also qualified by, and should be read together with, the risk factors included in “Part I, Item 1A. Risk Factors” in each Reporting Company’s Annual Report on Form 10-K for the year ended December 31, 2010 (2010 Form 10-K), and “Part II, Item 1A. Risk Factors” in each Reporting Company’s Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2011 and June 30, 2011 (the March and June 2011 Form 10-Qs), as filed with the Securities and Exchange Commission, and in this Form 10-Q, and investors should refer to those sections of the 2010 Form 10-K, the March and June 2011 Form 10-Qs and this Form 10-Q for more information on such risk factors.

Any forward-looking statements speak only as to the date of this Quarterly Report on Form 10-Q for each Reporting Company and each Reporting Company 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 a Reporting Company to predict all such factors, nor can the impact of any such factor be assessed on such Reporting Company’s business (viewed independently or together with the business or businesses of some or all of the other Reporting Companies) 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 factors should not be construed as exhaustive.

2

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 Income (Loss)		4		54		72		93
Consolidated Statements of Comprehensive Income		5		N/A		N/A		N/A
Consolidated Balance Sheets		6		55		73		94
Consolidated Statements of Cash Flows		8		57		75		96
Notes to Consolidated Financial Statements		9		58		76		97

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

3

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(millions of dollars, except per share data)
Operating Revenue
Power Delivery	$	1,329		$	1,600		$	3,671		$	4,011
Pepco Energy Services		312			457			993			1,480
Other		2			10			22			31
Total Operating Revenue		1,643			2,067			4,686			5,522
Operating Expenses
Fuel and purchased energy		943			1,319			2,747			3,683
Other services cost of sales		42			38			128			98
Other operation and maintenance		239			228			682			636
Restructuring charge		—			14			—			14
Depreciation and amortization		115			104			325			286
Other taxes		126			130			346			327
Gain on early termination of finance leases held in trust		—			—			(39	)		—
Deferred electric service costs		(17	)		13			(49	)		(69	)
Effects of Pepco divestiture-related claims		—			9			—			11
Total Operating Expenses		1,448			1,855			4,140			4,986
Operating Income		195			212			546			536
Other Income (Expenses)
Interest expense		(64	)		(68	)		(189	)		(240	)
Loss from equity investments		(3	)		—			(4	)		(1	)
Loss on extinguishment of debt		—			(135	)		—			(135	)
Other income		7			6			27			17
Total Other Expenses		(60	)		(197	)		(166	)		(359	)
Income from Continuing Operations Before Income Tax Expense		135			15			380			177
Income Tax Expense (Benefit) Related to Continuing Operations		55			(6	)		143			52
Net Income from Continuing Operations		80			21			237			125
(Loss) Income from Discontinued Operations, Net of Income Taxes		—			(4	)		1			(126	)
Net Income (Loss)		80			17			238			(1	)
Retained Earnings at Beginning of Period		1,095			1,130			1,059			1,268
Dividends paid on common stock (Note 15)		(61	)		(61	)		(183	)		(181	)
Retained Earnings at End of Period	$	1,114		$	1,086		$	1,114		$	1,086
Basic and Diluted Share Information
Weighted average shares outstanding (millions)		226			224			226			223
Earnings per share of common stock from Continuing Operations	$	0.35		$	0.09		$	1.05		$	0.56
Loss per share of common stock from Discontinued Operations		—			(0.01	)		—			(0.56	)
Basic and diluted earnings per share	$	0.35		$	0.08		$	1.05		$	—

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

4

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(millions of dollars)
Net Income (Loss)	$	80		$	17		$	238		$	(1	)
Other Comprehensive Income (Loss) from Continuing Operations
Gain (losses) from continuing operations on commodity derivatives designated as cash flow hedges:
Gains (losses) arising during period		—			(38	)		2			(116	)
Amount of losses reclassified into income		16			23			62			110
Net gains (losses) on commodity derivatives		16			(15	)		64			(6	)
Losses on treasury rate locks reclassified into income		1			15			1			18
Amortization of losses (gains) for prior service costs		2			—			(2	)		4
Prior service costs arising during period		(4	)		—			(4	)		—
Other comprehensive income from continuing operations, before income taxes		15			—			59			16
Income tax expense related to other comprehensive income from continuing operations		6			—			24			7
Other comprehensive income from continuing operations, net of income taxes		9			—			35			9
Other Comprehensive Income from Discontinued Operations, Net of Income Taxes		—			13			—			84
Comprehensive Income	$	89		$	30		$	273		$	92

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

5

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2011			December 31, 2010
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	103		$	20
Restricted cash equivalents		17			11
Accounts receivable, less allowance for uncollectible accounts of $54 million and $51 million, respectively		989			1,027
Inventories		146			126
Derivative assets		15			45
Prepayments of income taxes		147			276
Deferred income tax assets, net		69			90
Prepaid expenses and other		131			51
Conectiv Energy assets held for sale		1			111
Total Current Assets		1,618			1,757
INVESTMENTS AND OTHER ASSETS
Goodwill		1,407			1,407
Regulatory assets		1,915			1,915
Investment in finance leases held in trust		1,336			1,423
Income taxes receivable		85			114
Restricted cash equivalents		11			5
Assets and accrued interest related to uncertain tax positions		8			11
Other		169			169
Conectiv Energy assets held for sale		1			6
Total Investments and Other Assets		4,932			5,050
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		12,633			12,120
Accumulated depreciation		(4,613	)		(4,447	)
Net Property, Plant and Equipment		8,020			7,673
TOTAL ASSETS	$	14,570		$	14,480

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

6

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2011			December 31, 2010
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	545		$	534
Current portion of long-term debt and project funding		113			75
Accounts payable and accrued liabilities		534			587
Capital lease obligations due within one year		8			8
Taxes accrued		112			96
Interest accrued		80			45
Liabilities and accrued interest related to uncertain tax positions		3			3
Derivative liabilities		33			66
Other		255			321
Liabilities associated with Conectiv Energy assets held for sale		—			62
Total Current Liabilities		1,683			1,797
DEFERRED CREDITS
Regulatory liabilities		530			528
Deferred income taxes, net		2,891			2,714
Investment tax credits		23			26
Pension benefit obligation		239			332
Other postretirement benefit obligations		413			429
Income taxes payable		—			2
Liabilities and accrued interest related to uncertain tax positions		49			148
Derivative liabilities		8			21
Other		181			175
Liabilities associated with Conectiv Energy assets held for sale		—			10
Total Deferred Credits		4,334			4,385
LONG-TERM LIABILITIES
Long-term debt		3,794			3,629
Transition bonds issued by ACE Funding		306			332
Long-term project funding		14			15
Capital lease obligations		82			86
Total Long-Term Liabilities		4,196			4,062
COMMITMENTS AND CONTINGENCIES (NOTE 15)
EQUITY
Common stock, $.01 par value – authorized 400,000,000 shares, 226,879,348 and 225,082,252 shares outstanding, respectively		2			2
Premium on stock and other capital contributions		3,312			3,275
Accumulated other comprehensive loss		(71	)		(106	)
Retained earnings		1,114			1,059
Total Shareholders’ Equity		4,357			4,230
Non-controlling interest		—			6
Total Equity		4,357			4,236
TOTAL LIABILITIES AND EQUITY	$	14,570		$	14,480

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

7

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months  Ended September 30,
	2011			2010
	(millions of dollars)
OPERATING ACTIVITIES
Net income (loss)	$	238		$	(1	)
(Income) loss from discontinued operations		(1	)		126
Adjustments to reconcile net income (loss) to net cash from operating activities:
Depreciation and amortization		325			286
Non-cash rents from cross-border energy lease investments		(35	)		(41	)
Gain on early termination of finance leases held in trust		(39	)		—
Effects of Pepco divestiture-related claims		—			11
Deferred income taxes		165			258
Losses on treasury rate locks reclassified into income		1			18
Other		(13	)		(16	)
Changes in:
Accounts receivable		86			(39	)
Inventories		(20	)		(16	)
Prepaid expenses		(14	)		(8	)
Regulatory assets and liabilities, net		(108	)		(103	)
Accounts payable and accrued liabilities		(106	)		11
Pension contributions		(110	)		(100	)
Pension benefit obligation, excluding contributions		39			50
Cash collateral related to derivative activities		5			(23	)
Taxes accrued		(14	)		(98	)
Interest accrued		34			11
Other assets and liabilities		54			50
Conectiv Energy net assets held for sale		44			184
Net Cash From Operating Activities		531			560
INVESTING ACTIVITIES
Investment in property, plant and equipment		(639	)		(551	)
Department of Energy capital reimbursement awards received		27			3
Proceeds from the sale of Conectiv Energy wholesale power generation business		—			1,635
Proceeds from early termination of finance leases held in trust		161			—
Changes in restricted cash equivalents		(10	)		(2	)
Net other investing activities		(10	)		2
Investment in property, plant and equipment associated with Conectiv Energy assets held for sale		—			(138	)
Net Cash (Used By) From Investing Activities		(471	)		949
FINANCING ACTIVITIES
Dividends paid on common stock		(183	)		(181	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		36			36
Redemption of preferred stock of subsidiaries		(6	)		—
Issuances of long-term debt		235			102
Reacquisition of long-term debt		(60	)		(1,466	)
Issuances of short-term debt, net		11			10
Cost of issuances		(10	)		(6	)
Net other financing activities		(1	)		4
Net financing activities associated with Conectiv Energy assets held for sale		—			(10	)
Net Cash From (Used By) Financing Activities		22			(1,511	)
Net Increase (Decrease) in Cash and Cash Equivalents		82			(2	)
Cash and Cash Equivalents of discontinued operations		—			(16	)
Cash and Cash Equivalents at Beginning of Period		21			46
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	103		$	28
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes, net	$	—		$	14

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

8

PEPCO HOLDINGS

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PEPCO HOLDINGS, INC.

(1) ORGANIZATION

Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a holding company that, through the following regulated public utility subsidiaries, is engaged primarily in the transmission, distribution and default supply of electricity and the distribution and supply of natural gas (Power Delivery):

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

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

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

PHI and each of its utility subsidiaries is registered and files periodic reports with the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended. Together the three utilities constitute a single segment, Power Delivery, for financial reporting purposes.

Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy savings performance contracting services, primarily to commercial, industrial and government customers. Pepco Energy Services is in the process of winding down its competitive electricity and natural gas retail supply business. Pepco Energy Services constitutes a separate segment for financial reporting purposes.

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 PHI Service Company are charged to PHI and the participating operating subsidiaries in accordance with cost allocation methodologies set forth in the service agreement.

Power Delivery

Pepco, DPL and ACE are each regulated public utilities in the jurisdictions that comprise its service territory. Each utility owns and operates a network of wires, substations and other equipment that is classified as transmission facilities, distribution facilities or common facilities (which are used for both transmission and distribution). Transmission facilities are high-voltage systems that carry wholesale electricity into, or across, the utility’s service territory. Distribution facilities are low-voltage systems that carry electricity to end-use customers in the utility’s service territory.

Each utility is responsible for the distribution of electricity, and in the case of DPL, natural gas, in its service territory for which it is paid tariff rates established by the applicable local public service commissions. Each company also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is Standard Offer Service in Delaware, the District of Columbia and Maryland, and Basic Generation Service in New Jersey. In these Notes to the Consolidated Financial Statements, these supply service obligations are referred to generally as Default Electricity Supply.

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Pepco Energy Services

Pepco Energy Services is engaged in the following businesses:

• providing energy efficiency services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power and central energy plants,

• providing high voltage electric construction and maintenance services to customers throughout the United States and low voltage electric construction and maintenance services and streetlight construction and asset management services to utilities, municipalities and other customers in the Washington, D.C. metropolitan area, and

• retail supply of electricity and natural gas under its remaining contractual obligations.

Pepco Energy Services also owns and operates two oil-fired generation facilities that are scheduled for deactivation in May 2012.

In December 2009, PHI announced the wind down of the retail energy supply component of the Pepco Energy Services business. Pepco Energy Services is implementing this wind down by not entering into any new supply contracts while continuing to perform under its existing supply contracts through their respective expiration dates the last of which is June 1, 2014. The retail energy supply business has historically generated a substantial portion of the operating revenues and net income of the Pepco Energy Services segment. Operating revenues related to the retail energy supply business for the three months ended September 30, 2011 and 2010 were $217 million and $377 million, respectively, while operating income for the same periods was $5 million and $15 million, respectively. Operating revenues related to the retail energy supply business for the nine months ended September 30, 2011 and 2010 were $753 million and $1,275 million, respectively, while operating income for the same periods was $21 million and $45 million, respectively.

In connection with the operation of the retail energy supply business, Pepco Energy Services provided letters of credit of $1 million and posted cash collateral of $116 million as of September 30, 2011. These collateral requirements, which are based on existing wholesale energy purchase and sale contracts and current market prices, will decrease as the contracts expire, with the collateral expected to be fully released by June 1, 2014. The energy services business will not be affected by the wind down of the retail energy supply business.

Other Business Operations

Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy lease investments. This activity constitutes a third operating segment for financial reporting purposes, which is designated as “Other Non-Regulated.” For a discussion of PHI’s cross-border energy lease investments, see Note (7), “Leasing Activities,” and Note (15), “Commitments and Contingencies—Regulatory and Other Matters—PHI’s Cross-Border Energy Lease Investments.”

Discontinued Operations

In 2010, PHI disposed of Conectiv Energy Holding Company (Conectiv Energy). On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine Corporation (Calpine) for $1.64 billion. The disposition of all of Conectiv Energy’s remaining assets and businesses, consisting of its load service supply contracts, energy hedging portfolio, certain tolling agreements and other assets not included in the Calpine sale, is substantially complete. The operations of Conectiv Energy are being accounted for as a discontinued operation and no longer constitute a separate segment for financial reporting purposes. Substantially all of the information in these Notes to the Consolidated Financial Statements with respect to the operations of the former Conectiv Energy segment has been consolidated in Note (16), “Discontinued Operations.”

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(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, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in PHI’s Annual Report on Form 10-K for the year ended December 31, 2010. In the opinion of PHI’s management, the Consolidated Financial Statements contain all adjustments (which all are of a normal recurring nature) necessary to state fairly Pepco Holdings’ financial condition as of September 30, 2011, in accordance with GAAP. The year-end December 31, 2010 Consolidated Balance Sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and nine months ended September 30, 2011 may not be indicative of PHI’s results that will be realized for the full year ending December 31, 2011, since its Power Delivery business and the retail energy supply business of Pepco Energy Services are seasonal.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the Consolidated Financial Statements and accompanying notes. Although Pepco Holdings believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of goodwill and long-lived assets for impairment, fair value calculations for certain derivative instruments, the costs of providing pension and other postretirement benefits, evaluation of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of self-insurance reserves for general and auto liability claims, accrual of interest related to income taxes, accrual of restructuring charges, recognition of changes in network service transmission rates for prior service year costs, and the recognition of income tax benefits for investments in finance leases held in trust associated with PHI’s portfolio of cross-border energy lease investments. Additionally, PHI is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. PHI records an estimated liability for these proceedings and claims, when it is probable that a loss has been incurred and the loss is reasonably estimable.

Storm Costs

During the third quarter of 2011, Pepco, DPL and ACE incurred significant costs associated with Hurricane Irene that affected their respective service territories. Total incremental storm costs associated with Hurricane Irene were $47 million, with $30 million incurred for repair work and $17 million incurred as capital expenditures. Costs incurred for repair work of $24 million were deferred as a regulatory asset to reflect the probable recovery of these storm costs in certain jurisdictions, and the remaining $6 million was charged to Other operation and maintenance expense. Approximately $31 million of these total incremental storm costs have been estimated for the cost of restoration services provided by outside contractors since a large portion of the invoices for such services had not been received at September 30, 2011. Actual invoices may vary from these estimates. PHI’s utility subsidiaries currently plan to seek recovery of the incremental Hurricane Irene costs in each of their various jurisdictions in pending or planned distribution rate case filings.

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Network Service Transmission Rates

In May 2011, PHI’s utility subsidiaries filed their network service transmission rates with the Federal Energy Regulatory Commission effective for the service year beginning June 1, 2011. The new rates include an adjustment for costs incurred in the service year ended May 31, 2011 that were not reflected in the rates charged to customers for that service year. In the second quarter of 2011, PHI’s utility subsidiaries recorded a $3 million decrease in transmission revenues as a change to the estimates recorded in previous periods primarily due to a decrease in the actual rate base versus the estimated rate base.

For the nine months ended September 30, 2010, PHI’s utilities recorded an $8 million increase in transmission revenues associated with a change to the estimates recorded in previous periods.

General and Auto Liability

During the second quarter of 2011, PHI’s utility subsidiaries reduced their self-insurance reserves for general and auto liability claims by approximately $5 million, based on obtaining an actuarial estimate of the unpaid loss attributed to general and auto liability claims for each of PHI’s utility subsidiaries at June 30, 2011.

Consolidation of Variable Interest Entities

In accordance with the provisions of the Financial Accounting Standards Board (FASB) guidance on the consolidation of variable interest entities (Accounting Standards Codification (ASC) 810), Pepco Holdings consolidates variable interest entities with respect to which Pepco Holdings or a subsidiary is the primary beneficiary. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. The subsidiaries of Pepco Holdings have contractual arrangements with several entities to which the guidance applies.

ACE Power Purchase Agreements

PHI, through its ACE subsidiary, is a party to three power purchase agreements (PPAs) with unaffiliated, non-utility generators (NUGs). PHI was unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary and as a result has applied the scope exemption from the consolidation guidance for enterprises that have not been able to obtain such information.

Net purchase activities with the NUGs for the three months ended September 30, 2011 and 2010, were approximately $57 million and $82 million, respectively, of which approximately $55 million and $74 million, respectively, consisted of power purchases under the PPAs. Net purchase activities with the NUGs for the nine months ended September 30, 2011 and 2010, were approximately $169 million and $222 million, respectively, of which approximately $159 million and $203 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACE’s customers through regulated rates.

DPL Renewable Energy Transactions

DPL is subject to Renewable Energy Portfolio Standards (RPS) in the state of Delaware that require it to obtain renewable energy credits (RECs) for energy delivered to its customers. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its customers by law. PHI, through its DPL subsidiary, has entered into three land-based wind PPAs and one offshore wind PPA in the aggregate amount of 328 megawatts and one solar PPA with a 10 megawatt facility as of September 30, 2011. As the wind facilities become operational, DPL is obligated to purchase energy and RECs in amounts generated and delivered by the facilities at rates that are primarily fixed under these agreements. Under one of the PPAs, DPL is also obligated to purchase the capacity associated with the facility at rates that are generally fixed. If a wind facility does not become operational by a specified date, DPL has the right to terminate that PPA. DPL

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concluded that consolidation is not required for any of these agreements under FASB guidance on the consolidation of variable interest entities.

Two of the land-based facilities are operational and DPL is obligated to purchase energy and RECs from one of these facilities through 2024 in amounts not to exceed 50.25 megawatts and the second of these facilities through 2031 in amounts not to exceed 40 megawatts. DPL’s purchases under the operational wind PPAs totaled $3 million and $2 million for the three months ended September 30, 2011 and 2010, respectively, and $12 million and $8 million for the nine months ended September 30, 2011 and 2010, respectively. The other land-based wind agreement has a 20-year term and the facility is currently expected to become operational during 2011. In July 2011, the Delaware Public Service Commission (DPSC) approved amendments to this land-based wind PPA to change the location of the facility and to reduce the maximum generation capacity from 60 megawatts to 38 megawatts.

The offshore wind facility is expected to become operational during 2016. If the offshore wind facility developer is unable to obtain all necessary permits and financing commitments, this could result in delays in the construction schedule and the operational start date of the offshore wind facility.

The solar facility began operations in the third quarter of 2011. The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase RECs in an amount up to 70 percent of the energy output at a fixed price.DPL’s purchases under the agreement were $1 million during the third quarter of 2011.

On October 18, 2011, the DPSC approved a tariff submitted by DPL specific to a 30 megawatt fuel cell facility to be constructed using fuel cells manufactured in the State of Delaware. The RPS require that the DPSC establish an irrevocable tariff under which DPL would be an agent that collects payments from its customers and disburses the amounts collected to a Qualified Fuel Cell Provider that deploys Delaware-manufactured fuel cells as part of a 30 megawatt generation facility. The tariff and the RPS establish that DPL would be an agent to collect payments in advance from its distribution customers and remit them to the Qualified Fuel Cell Provider for each megawatt hour of energy produced over 20 years. DPL would have no liability to the Qualified Fuel Cell Provider other than to remit payments collected from its distribution customers pursuant to the tariff. The RPS provide for a reduction in DPL’s REC requirements based upon the actual energy output of the facility. PHI is currently assessing the appropriate accounting treatment for the transaction, including the applicability of FASB guidance on the consolidation of variable interest entities, leases, and derivative instruments. PHI’s accounting review is expected to be completed in the fourth quarter of 2011.

Atlantic City Electric Transition Funding LLC

Atlantic City Electric Transition Funding LLC (ACE Funding) was established in 2001 by ACE solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of bonds (Transition Bonds). The proceeds of the sale of each series of Transition Bonds have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect non-bypassable transition bond charges (the Transition Bond Charges) from ACE customers pursuant to bondable stranded costs rate orders issued by the New Jersey Board of Public Utilities (NJBPU) in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). ACE collects the Transition Bond Charges from its customers on behalf of ACE Funding and the holders of the Transition Bonds. The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACE’s customers, are not available to creditors of ACE. The holders of the Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding and PHI consolidates ACE Funding in its financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

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ACE Standard Offer Capacity Agreements

On April 28, 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. The SOCAs were established under a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey. The SOCAs are 15-year, financially settled transactions approved by the NJBPU that allow generators to receive payments from, or make payments to, ACE based on the difference between the fixed price in the SOCAs and the price for capacity that clears PJM Interconnection, LLC (PJM). Each of the other electricity distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. The annual share of payments or receipts for ACE and the other EDCs is based upon each company’s annual proportion of the total New Jersey load attributable to all EDCs. ACE and the other EDCs entered the SOCAs under protest based on concerns about the potential cost to distribution customers. In February 2011, ACE joined other plaintiffs in an action filed in the United States District Court for the District of New Jersey challenging the constitutionality of the New Jersey law. The proceeding is now in the discovery phase. In May 2011, the NJBPU denied a joint motion for reconsideration of its order requiring each of the EDCs to enter into the SOCAs. In June 2011, ACE and the other EDCs filed appeals related to the NJBPU orders with the Appellate Division of the New Jersey Superior Court.

On October 17, 2011, one of the generation companies sent a notice of dispute under the SOCA to ACE. The notice of dispute alleges that certain actions taken by PJM have an adverse effect on the generation company’s ability to clear the PJM auction as required by the SOCA and, under a provision of the SOCA, ACE and the generation supplier must attempt to amend the SOCA in order to permit transactions to continue thereunder, subject to NJBPU approval. ACE has agreed to meet with the generation supplier, but does not acknowledge that a “dispute” exists under the SOCA.

Currently, PHI believes that FASB guidance on derivative accounting and the accounting for regulated operations would apply to a SOCA once capacity has cleared a PJM auction. Once cleared, the gain (loss) associated with the fair value of a derivative would be offset by the establishment of a regulatory liability (asset).

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. Substantially all of Pepco Holdings’ goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated entirely to Pepco Holdings’ Power Delivery reporting unit for purposes of impairment testing based on the aggregation of its components. Pepco Holdings tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; a decline in PHI’s stock price causing market capitalization to fall further below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI concluded that an interim impairment test was not required during the three months ended September 30, 2011.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $111 million and $118 million for the three months ended September 30, 2011 and 2010, respectively, and $302 million and $280 million for the nine months ended September 30, 2011 and 2010, respectively.

Reclassifications and Adjustments

Certain prior period amounts have been reclassified in order to conform to the current period presentation. The following adjustments have been recorded and are not considered material either individually or in the aggregate:

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Default Electricity Supply Revenue and Costs Adjustments

During 2011, DPL recorded adjustments associated with the accounting for Default Electricity Supply revenue and costs. These adjustments were primarily due to the under-recognition of allowed returns on working capital and under-recoveries of administrative costs and resulted in a pre-tax decrease in Other operation and maintenance expense of $1 million and $9 million for the three and nine months ended September 30, 2011, respectively.

Pepco Energy Services Derivative Accounting Adjustments

During the first quarter of 2011, PHI recorded an adjustment associated with an increase in the value of certain derivatives from October 1, 2010 to December 31, 2010, which had been erroneously recorded in other comprehensive income at December 31, 2010. This adjustment resulted in an increase in revenue and pre-tax earnings of $2 million for the nine months ended September 30, 2011.

Other Taxes Adjustment

In the third quarter of 2010, Pepco recorded an adjustment to correct certain errors related to other taxes which resulted in a decrease to Other taxes expense of $5 million (pre-tax) for the three and nine months ended September 30, 2010.

Income Tax Adjustments

During the first quarter of 2011, Pepco recorded an adjustment to correct certain income tax errors related to prior periods associated with the interest on uncertain tax positions. The adjustment resulted in an increase in income tax expense of $1 million for the nine months ended September 30, 2011.

During the second quarter of 2010, PHI recorded an adjustment to correct certain income tax errors associated with casualty loss claims, which resulted in a decrease to income tax expense of $1 million for the nine months ended September 30, 2010.

During the first quarter of 2010, ACE recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment resulted in an increase in income tax expense of $6 million for the nine months ended September 30, 2010. The adjustment represents the reversal of erroneously recorded interest income for state income tax purposes related to uncertain and effectively settled tax positions, including $2 million, $3 million and $1 million recorded in 2009, 2008 and 2007, respectively.

During 2010, PHI recorded various adjustments to income tax expense to reflect primarily the benefit from additional deductions related to executive compensation that had erroneously not been included in tax returns prior to 2008, a reduction in income tax expense associated with errors related to the deferred tax assets established in connection with the District of Columbia net operating losses, and an increase to income tax expense associated with the reversal of erroneously recorded interest income for state income tax purposes related to uncertain and effectively settled tax positions. These adjustments resulted in a decrease to income tax expense of $7 million related to continuing operations for the three months ended September 30, 2010 and a decrease to income tax expense of $1 million related to continuing operations for the nine months ended September 30, 2010.

In the third quarter of 2010, Pepco recorded certain adjustments to correct errors in Income tax expense which resulted in an increase to Income tax expense of $4 million for the three and nine months ended September 30, 2010.

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Discontinued Operations

In the third quarter of 2010, PHI recorded adjustments to reverse revenue erroneously recognized in the second quarter of 2010 associated with its discontinued operations. The adjustments resulted in an increase in net loss from discontinued operations of $7 million (pre-tax) for the three months ended September 30, 2010.

(3)NEWLY ADOPTED ACCOUNTING STANDARDS

Fair Value Measurements and Disclosures (ASC 820)

The FASB issued new disclosure requirements that require significant items within the reconciliation of the Level 3 valuation category to be presented in separate categories for purchases, sales, issuances and settlements. The guidance was effective beginning with PHI’s March 31, 2011 financial statements. PHI has included the new disclosure requirements in Note (14), “Fair Value Disclosures,” to its consolidated financial statements.

Goodwill (ASC 350)

The FASB issued new guidance on performing goodwill impairment tests that was effective beginning January 1, 2011 for PHI. Under the new guidance, the carrying value of the reporting unit must include the liabilities that are part of the capital structure of the reporting unit. PHI already allocates liabilities to the reporting unit when performing its goodwill impairment test, so the new guidance did not change PHI’s goodwill impairment test methodology.

Revenue Recognition (ASC 605)

The FASB issued new guidance to help determine separate units of accounting for multiple-deliverables within a single contract that was effective beginning January 1, 2011 for PHI. The energy services contracts of Pepco Energy Services are primarily impacted by this guidance because they often have multiple elements, which could include design, installation, operation and maintenance, and measurement and verification services. PHI and its subsidiaries adopted the new guidance, effective January 1, 2011, and it did not have a material impact on Pepco Energy Services’ revenue recognition methods or results of operations nor did it have a material impact on PHI’s overall financial condition, results of operations or cash flows.

(4)RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements and Disclosures (ASC 820)

In May 2011, the FASB issued new guidance on fair value measurement and disclosures that will be effective beginning with PHI’s March 31, 2012 consolidated financial statements. The new guidance will change how fair value is measured in specific instances and expand disclosures about fair value measurements. PHI is evaluating the impact of this new guidance on its consolidated financial statements.

Comprehensive Income (ASC 220)

In June 2011, the FASB issued new guidance that requires entities to report comprehensive income in one of two ways: (i) one single continuous statement that combines the income statement with the statement of other comprehensive income and totals to a comprehensive income amount; or (ii) in two separate but consecutive statements of income and other comprehensive income. PHI currently applies the second option in its financial statements, so PHI expects that this guidance will have minimal impact. The new guidance is effective beginning with PHI’s March 31, 2012 consolidated financial statements.

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Goodwill (ASC 350)

In September 2011, the FASB issued new guidance that changes the annual and interim assessments of goodwill for impairment. The new guidance modifies the required annual impairment test by giving entities the option to perform a qualitative assessment of whether it is more likely than not that goodwill is impaired before performing a quantitative assessment. The new guidance also amends the events and circumstances that entities should assess to determine whether an interim quantitative impairment test is necessary. The new guidance is effective beginning with PHI’s March 31, 2012 consolidated financial statements and PHI is evaluating the impact. The new guidance can be adopted prior to March 31, 2012 but PHI does not plan to employ the new qualitative assessment as part of its November 1, 2011 annual impairment test.

(5) SEGMENT INFORMATION

Pepco Holdings’ management has identified its operating segments at September 30, 2011 as Power Delivery, Pepco Energy Services and Other Non-Regulated. In the tables below, the Corporate and Other column is included to reconcile the segment data with consolidated data and includes unallocated Pepco Holdings’ (parent company) capital costs, such as financing costs. Segment financial information for continuing operations for the three and nine months ended September 30, 2011 and 2010 is as follows:

	Three Months Ended September 30, 2011
	(millions of dollars)
	Power Delivery		Pepco Energy Services		Other Non- Regulated			Corporate and Other (a)			PHI Consolidated
Operating Revenue	$	1,329	$	312	$	7		$	(5	)	$	1,643
Operating Expenses (b)		1,167		300		2			(21	)		1,448
Operating Income		162		12		5			16			195
Interest Income		1		1		—			(2	)		—
Interest Expense		53		1		3			7			64
Other Income (Expense)		7		1		(3	)		(1	)		4
Preferred Stock Dividends		—		—		1			(1	)		—
Income Tax Expense (Benefit)		51		5		(7	)		6			55
Net Income from Continuing Operations		66		8		5			1			80
Total Assets (excluding Assets Held For Sale)		11,015		611		1,467			1,475			14,568
Construction Expenditures	$	239	$	4	$	—		$	9		$	252

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit the Power Delivery business. These expenditures are recorded as incurred in the Corporate and Other segment and are allocated to Power Delivery once the assets are placed in service. Additionally, Corporate and Other includes intercompany amounts of $(5) million for Operating Revenue, $(6) million for Operating Expense, $(7) million for Interest Income and $(6) million for Interest Expense.

(b) Includes depreciation and amortization of $115 million, consisting of $107 million for Power Delivery, $4 million for Pepco Energy Services, and $4 million for Corporate and Other.

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	Three Months Ended September 30, 2010
	(millions of dollars)
	Power Delivery			Pepco Energy Services		Other Non- Regulated			Corporate and Other (a)			PHI Consolidated
Operating Revenue	$	1,600		$	457	$	15		$	(5	)	$	2,067
Operating Expenses (b) (c)		1,418	(d)		442		—			(5	)		1,855
Operating Income		182			15		15			—			212
Interest Expense		51			3		2			12			68
Other Income (Expense)		6			—		(1	)		1			6
Loss on Extinguishment of Debt		—			—		—			135			135
Preferred Stock Dividends		—			—		1			(1	)		—
Income Tax Expense (Benefit)		61			4		2			(73	)(e)		(6	)
Net Income (Loss) from Continuing Operations		76			8		9			(72	)		21
Total Assets (excluding Assets Held For Sale)		10,569			617		1,524			1,325			14,035
Construction Expenditures	$	181		$	2	$	—		$	4		$	187

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit the Power Delivery business. These expenditures are recorded as incurred in the Corporate and Other segment and are allocated to Power Delivery once the assets are placed in service. Additionally, Corporate and Other includes intercompany amounts of $(5) million for Operating Revenue, $(2) million for Operating Expense, $(6) million for Interest Income, $(5) million for Interest Expense, and $(1) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization of $104 million, consisting of $97 million for Power Delivery, $5 million for Pepco Energy Services and $2 million for Corporate and Other.

(c) Includes restructuring charge of $14 million, consisting of $13 million for Power Delivery and $1 million for Corporate and Other.

(d) Includes $9 million expense related to effects of Pepco divestiture-related claims.

(e) Includes current state tax benefits resulting from the restructuring of certain Pepco Holdings subsidiaries which have subjected Pepco Holdings to state income taxes in new jurisdictions.

	Nine Months Ended September 30, 2011
	(millions of dollars)
	Power Delivery		Pepco Energy Services		Other Non- Regulated			Corporate and Other (a)			PHI Consolidated
Operating Revenue	$	3,671	$	993	$	35		$	(13	)	$	4,686
Operating Expenses (b)		3,255		952		(34	)(c)		(33	)		4,140
Operating Income		416		41		69			20			546
Interest Income		1		1		2			(4	)		—
Interest Expense		155		3		10			21			189
Other Income (Expenses)		23		3		(4	)		1			23
Preferred Stock Dividends		—		—		2			(2	)		—
Income Tax Expense (d)		100		16		25			2			143
Net Income (Loss) from Continuing Operations		185		26		30	(c)		(4	)		237
Total Assets (excluding Assets Held For Sale)		11,015		611		1,467			1,475			14,568
Construction Expenditures	$	603	$	11	$	—		$	25		$	639

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit the Power Delivery business. These expenditures are recorded as incurred in the Corporate and Other segment and are allocated to Power Delivery once the assets are placed in service. Additionally, Corporate and Other includes intercompany amounts of $(13) million for Operating Revenue, $(12) million for Operating Expense, $(17) million for Interest Income, $(15) million for Interest Expense, and $(2) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization of $325 million, consisting of $301 million for Power Delivery, $13 million for Pepco Energy Services, $1 million for Other Non-Regulated, and $10 million for Corporate and Other.

(c) Includes $39 million pre-tax ($3 million after-tax) gain from the early termination of cross-border energy leases held in trust.

(d) Includes tax benefits of $14 million for Power Delivery primarily associated with an interest benefit related to federal tax liabilities and a $22 million reversal of previously recognized tax benefits for Other Non-Regulated associated with the early termination of cross-border energy leases held in trust.

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	Nine Months Ended September 30, 2010
	(millions of dollars)
	Power Delivery			Pepco Energy Services		Other Non- Regulated				Corporate and Other (a)			PHI Consolidated
Operating Revenue	$	4,011		$	1,480	$	41			$	(10	)	$	5,522
Operating Expenses (b) (c)		3,583	(d)		1,417		3				(17	)		4,986
Operating Income		428			63		38				7			536
Interest Income		1			—		2				(3	)		—
Interest Expense		155			13		9				63			240
Other Income (Expenses)		15			1		(2	)	��		2			16
Loss on Extinguishment of Debt		—			—		—				135			135
Preferred Stock Dividends		—			—		2				(2	)		—
Income Tax Expense (Benefit)		128	(e)		20		8				(104	)(f)		52
Net Income (Loss) from Continuing Operations		161			31		19				(86	)		125
Total Assets (excluding Assets Held For Sale)		10,569			617		1,524				1,325			14,035
Construction Expenditures	$	526		$	3	$	—			$	22		$	551

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to the Power Delivery segment for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit the Power Delivery business. These expenditures are recorded as incurred in the Corporate and Other segment and are allocated to Power Delivery once the assets are placed in service. Additionally, Corporate and Other includes intercompany amounts of $(10) million for Operating Revenue, $(7) million for Operating Expense, $(31) million for Interest Income, $(30) million for Interest Expense, and $(2) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization of $286 million, consisting of $264 million for Power Delivery, $14 million for Pepco Energy Services, $1 million for Other Non-Regulated and $7 million for Corporate and Other.

(c) Includes restructuring charge of $14 million, consisting of $13 million for Power Delivery and $1 million for Corporate and Other.

(d) Includes $11 million expense related to effects of Pepco divestiture-related claims.

(e) Includes $8 million reversal of accrued interest income on uncertain and effectively settled state income tax positions.

(f) Includes $14 million of state tax benefits resulting from the restructuring of certain Pepco Holdings subsidiaries, partially offset by a charge of $4 million to write off deferred tax assets related to the Medicare Part D subsidy.

(6) GOODWILL

PHI’s goodwill balance of $1.4 billion was unchanged during the three and nine months ended September 30, 2011. Substantially all of PHI’s goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated entirely to the Power Delivery reporting unit based on the aggregation of its regulated public utility company components for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350).

PHI’s annual impairment test as of November 1, 2010 indicated that goodwill was not impaired. For the three months ended September 30, 2011, PHI concluded that there were no events requiring it to perform an interim goodwill impairment test. PHI will perform its next annual impairment test as of November 1, 2011.

(7) LEASING ACTIVITIES

Investment in Finance Leases Held in Trust

PHI has a portfolio of cross-border energy lease investments (the lease portfolio) consisting of hydroelectric generation facilities, coal-fired electric generation facilities and natural gas distribution networks located outside of the United States. Each lease investment is comprised of a number of leases. As of September 30, 2011 and December 31, 2010, the lease portfolio consisted of seven investments with an aggregate book value of $1.3 billion and eight investments with an aggregate book value of $1.4 billion, respectively.

In the third quarter of 2011, PHI modified its tax cash flow assumptions for two of the investments in the lease portfolio associated with the change in tax laws in the District of Columbia as further discussed in Note (15), “Commitments and Contingencies—District of Columbia Tax Legislation.” Accordingly, PHI recalculated the equity investment and recorded a $7 million pre-tax ($3 million after-tax) charge.

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During the second quarter of 2011, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the eight lease investments and a small portion of the leases comprising a second lease investment. The early terminations of the leases were negotiated at the request of the lessees and were completed in June 2011. PHI received net cash proceeds of $161 million (net of a termination payment of $423 million used to retire the non-recourse debt associated with the terminated leases) and recorded a pre-tax gain of $39 million, representing the excess of the net cash proceeds over the carrying value of the lease investments.

With respect to the terminated leases, PHI had previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. Because the leases were terminated prior to the end of the stated term, management decided not to pursue these opportunities and $22 million in certain Federal income tax benefits recognized previously were reversed. The after-tax gain on the lease terminations was $3 million, reflecting an income tax provision at the statutory federal rate of $14 million and the income tax benefit reversal. PHI has no intent to terminate early any other leases in the lease portfolio. With respect to certain of these remaining leases, management’s assumption continues to be that the foreign earnings recognized at the end of the lease term will remain invested abroad.

The components of the cross-border energy lease investments at September 30, 2011 and at December 31, 2010 are summarized below:

	September 30, 2011			December 31, 2010
	(millions of dollars)
Scheduled lease payments to PHI, net of non-recourse debt	$	2,120		$	2,265
Less: Unearned and deferred income		(784	)		(842	)
Investment in finance leases held in trust		1,336			1,423
Less: Deferred income tax liabilities		(742	)		(816	)
Net investment in finance leases held in trust	$	594		$	607

Income recognized from cross-border energy lease investments, excluding the gain on the terminated leases discussed above, was comprised of the following for the three and nine months ended September 30, 2011 and 2010:

	Three Months  Ended September 30,					Nine Months  Ended September 30,
	2011			2010		2011		2010
	(millions of dollars)
Pre-tax income from PHI’s cross-border energy lease investments (included in “Other Operating Revenue”)	$	7		$	15	$	35	$	41
Income tax (benefit) expense related to cross-border energy lease investments		(3	)		4		7		11
Net income from PHI’s cross-border energy lease investments	$	10		$	11	$	28	$	30

PHI regularly monitors the financial performance and condition of the lessees under its cross-border energy lease investments. Changes in credit quality are assessed to determine if they should be reflected in the carrying value of the leases. PHI reviews each lessee’s performance versus annual compliance requirements set by the terms and conditions of the leases. This includes a comparison of published credit ratings to minimum credit rating requirements in the leases for lessees with public credit ratings. In addition, PHI routinely meets with senior executives of the lessees to discuss the lessee company and asset performance. If the annual compliance requirements or minimum credit ratings are not met, remedies are available under the leases. PHI believes that all lessees were in compliance with the terms and conditions of their lease agreements at September 30, 2011.

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The table below shows PHI’s net investment in these leases by the published credit ratings of the lessees as of September 30, 2011 and December 31, 2010:

Lessee Rating (a)	September 30, 2011		December 31, 2010
	(millions of dollars)
Rated Entities
AA/Aa and above	$	730	$	709
A		533		549
Total		1,263		1,258
Non Rated Entities		73		165
Total	$	1,336	$	1,423

(a) Excludes the credit ratings associated with collateral posted by the lessees in these transactions.

(8) PENSION AND OTHER POSTRETIREMENT BENEFITS

The following Pepco Holdings information is for the three months ended September 30, 2011 and 2010:

	Pension Benefits						Other  Postretirement Benefits
	2011			2010			2011			2010
	(millions of dollars)
Service cost	$	10		$	8		$	1		$	1
Interest cost		27			28			10			10
Expected return on plan assets		(32	)		(30	)		(5	)		(4	)
Amortization of prior service cost		—			—			(1	)		(1	)
Amortization of net actuarial loss		11			11			3			3
Net periodic benefit cost	$	16		$	17		$	8		$	9

The following Pepco Holdings information is for the nine months ended September 30, 2011 and 2010:

	Pension Benefits						Other  Postretirement Benefits
	2011			2010			2011			2010
	(millions of dollars)
Service cost	$	27		$	26		$	4		$	4
Interest cost		80			83			28			29
Expected return on plan assets		(96	)		(88	)		(14	)		(12	)
Amortization of prior service cost		(1	)		—			(3	)		(3	)
Amortization of net actuarial loss		35			32			9			9
Plan amendment		—			1			—			—
Termination benefits		—			—			1			5
Net periodic benefit cost	$	45		$	54		$	25		$	32

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Pension and Other Postretirement Benefits

Net periodic benefit cost related to continuing operations is included in “Other operation and maintenance” expense, net of the portion of the net periodic benefit cost that is capitalized as part of the cost of labor for internal construction projects. PHI’s pension and other postretirement net periodic benefits cost for the three and nine months ended September 30, 2010, includes one-time charges in the aggregate amount of $6 million related to the sale of Conectiv Energy. After intercompany allocations, the three utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and other postretirement benefit costs related to continuing operations.

Pension Contributions

PHI’s funding policy with regard to PHI’s non-contributory retirement plan (the PHI Retirement Plan) is to maintain a funding level that is at least equal to the funding target level under the Pension Protection Act of 2006. Under the Pension Protection Act, if a plan incurs a funding shortfall in the preceding plan year, there can be required minimum quarterly contributions in the current and following plan years. Although PHI had no minimum funding requirement under the Pension Protection Act guidelines, Pepco, ACE and DPL, in the first quarter of 2011, made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $40 million, $30 million and $40 million, respectively. The $110 million in contributions brought the PHI Retirement Plan assets to the funding target level for 2011 under the Pension Protection Act. During 2010, PHI Service Company made discretionary tax-deductible contributions totaling $100 million to the PHI Retirement Plan, which brought plan assets to the funding target level for 2010 under the Pension Protection Act. Pepco, ACE and DPL did not make contributions to the PHI Retirement Plan in 2010.

Investment Policies and Strategies

In PHI’s December 31, 2010 Form 10-K, PHI reported asset allocations for the PHI Retirement Plan at December 31, 2010 of 53% in equity investments, 40% in fixed income investments and 7% in Other investments (real estate, private equity).

In the first quarter of 2011, PHI modified its pension investment policy and strategy to reduce the effects of future volatility of the fair value of its pension assets relative to its pension liabilities. The new strategy was implemented during the second quarter of 2011 and is commonly referred to as a Liability-Driven Investment (LDI) strategy. Under the new LDI strategy, the plan’s allocation to fixed income investments, primarily high quality, longer-maturity fixed income securities was increased, with a reduction in the allocation to equity investments. PHI anticipates further increases in the allocation to fixed income investments, with a corresponding reduction in the allocation to equity investments, as the funded status of its plan increases.

Benefit Plan Modifications

On July 28, 2011, PHI’s Board of Directors approved revisions to certain of PHI’s existing benefit programs, including the PHI Retirement Plan. The changes to the PHI Retirement Plan were effected by PHI in order to establish a more unified approach to PHI’s retirement programs and to further align the benefits offered under PHI’s retirement programs. The changes to the PHI Retirement Plan will be effective on or after January 1, 2012 and will affect the retirement benefits payable to approximately 750 of PHI’s employees. On September 22, 2011, the PHI Administrative Board approved another amendment revising the effective date to July 1, 2011. All full time employees of PHI and certain subsidiaries are eligible to participate in the PHI Retirement Plan. Retirement benefits for all other employees remain unchanged.

On July 28, 2011, PHI’s Board also approved a new, non-tax-qualified Supplemental Executive Retirement Plan (SERP) which will replace PHI’s two pre-existing supplemental retirement plans, effective August 1, 2011. As of the effective date of the new SERP, the Conectiv SERP and the PHI Combined SERP were closed to new participants. The establishment of the new SERP is consistent with PHI’s efforts to align retirement benefits for PHI and its subsidiaries with current market practices and to provide similarly situated

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participants with retirement benefits that are the same or similar in value as compared to the benefits provided under the prior SERPs.

The benefit plan modifications did not have a material impact on PHI’s overall financial condition, results of operations, or cash flows.

(9) DEBT

Credit Facilities

On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amendment and restatement of their $1.5 billion credit facility to extend the expiration date of the facility to August 1, 2016, and to make various other changes. As amended and restated, all or any portion of the facility may be used to obtain revolving loans and up to $500 million may be used to obtain letters of credit. PHI’s credit sublimit under the facility is $750 million and the sublimit of each of Pepco, DPL and ACE is $250 million. The borrowers may increase or decrease their respective sublimits during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of sublimit reallocations cannot exceed eight per fiscal year during the term of the agreement.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and one month LIBOR plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. The facility also includes a “swingline loan sub-facility,” pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt thereof. All indebtedness incurred under the facility is unsecured.

There are no rating triggers associated with the credit facility. As of September 30, 2011, each borrower was in compliance with the covenants applicable to it under the credit facility.

Additionally, PHI had two bi-lateral 364-day unsecured credit agreements totaling $200 million, each of which expired according to its terms on October 26, 2011. Under each of those credit agreements, PHI had access to revolving and floating rate loans over the terms of the agreements. These facilities were established to provide additional liquidity and collateral support for Pepco Energy Services’ retail energy supply business. Based on the progress made toward winding down the retail energy supply business, the level of liquidity and collateral needed to support this business has decreased. As a result, PHI concluded that these credit agreements were no longer needed.

At September 30, 2011 and December 31, 2010, the amount of cash plus unused borrowing capacity under the credit facilities available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $1.4 billion and $1.2 billion, respectively. PHI’s utility subsidiaries had combined cash and unused borrowing capacity under the $1.5 billion credit facility of $831 million and $462 million at September 30, 2011 and December 31, 2010, respectively.

Other Financing Activities

In July 2011, ACE Funding made principal payments of $6 million on its Series 2002-1 Bonds, Class A-3, and $2 million on its Series 2003-1 Bonds, Class A-2.

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Loss on Extinguishment of Debt

In July 2010, PHI purchased, pursuant to a cash tender offer, $640 million in principal amount of its 6.45% Senior Notes due 2012 (6.45% Notes), redeemed the remaining $110 million of outstanding 6.45% Notes, and purchased, pursuant to a cash tender offer, $129 million of its 6.125% Senior Notes due 2017 (6.125% Notes) and $65 million of 7.45% Senior Notes due 2032 (7.45% Notes). The purchases of the 6.45% Notes, 6.125% Notes and the 7.45% Notes were funded using the proceeds realized by PHI from the sale of Conectiv Energy’s wholesale power generation business. In connection with these transactions, PHI recorded a pre-tax loss on extinguishment of debt of $120 million in the third quarter of 2010.

In connection with the purchases of the 6.45% Notes and the 7.45% Notes, PHI accelerated the recognition of $15 million of pre-tax hedging losses attributable to the issuance of the 6.45% Notes and 7.45% Notes by reclassifying these hedging losses from AOCL to the income statement in the third quarter of 2010. These hedging losses originally arose when PHI entered into several treasury rate lock transactions in June 2002 to hedge changes in interest rates related to the anticipated issuance in August 2002 of several series of senior notes, including the 6.45% Notes and the 7.45% Notes. Upon issuance of the fixed rate debt in August 2002, the rate locks were terminated at a loss that has been deferred in AOCL and is being recognized in income over the life of the debt issued as interest payments on the debt are made. The accelerated recognition of these losses has also been included as a component of pre-tax loss on extinguishment of debt.

Financing Activities Subsequent to September 30, 2011

In October 2011, ACE Funding made principal payments of $8 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

Collateral Requirements of Pepco Energy Services

In the ordinary course of its retail energy supply business which is in the process of winding down, Pepco Energy Services enters into various contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce its financial exposure to changes in the value of its assets and obligations due to energy price fluctuations. These contracts typically have collateral requirements. Depending on the contract terms, the collateral required to be posted by Pepco Energy Services can be of varying forms, including cash and letters of credit.

During periods of declining energy prices, Pepco Energy Services has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees, (i) assumed, by novation, the electricity purchase obligations of Pepco Energy Services in years 2009 through 2011 under several wholesale purchase contracts, and (ii) agreed to supply electricity to Pepco Energy Services on the same terms as the novated transactions, but without imposing on Pepco Energy Services any obligation to post collateral based on changes in electricity prices. The upfront fees incurred by Pepco Energy Services in 2009 in the amount of $25 million are being amortized into expense in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of the novation. For the three months ended September 30, 2011 and 2010, Pepco Energy Services recognized less than $1 million and approximately $1 million, respectively, of the fees in “Interest expense.” For the nine months ended September 30, 2011 and 2010, Pepco Energy Services recognized approximately $1 million and $6 million, respectively, of the fees in “Interest expense.”

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As of September 30, 2011, Pepco Energy Services had posted net cash collateral of $116 million and provided letters of credit of $1 million. At December 31, 2010, Pepco Energy Services had posted net cash collateral of $117 million and provided letters of credit of $113 million. As its retail energy supply business is wound down, Pepco Energy Services’ collateral requirements will be further reduced.

At September 30, 2011 and December 31, 2010, the aggregate amount of cash plus unused borrowing capacity under the credit facilities available to meet the combined future liquidity needs of Pepco Energy Services totaled $547 million and $728 million, respectively.

(10) INCOME TAXES

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

	Three Months Ended September 30,										Nine Months Ended September 30,
	2011					2010					2011					2010
	(millions of dollars)
Income tax at federal statutory rate	$	47		35.0	%	$	5		35.0	%	$	133		35.0	%	$	62		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		9		6.7			(6	)	(37.3	)		19		5.0			4		2.0
Depreciation		(1	)	(0.7	)		2		9.3			(2	)	(0.5	)		4		2.4
Cross-border energy lease investments		(5	)	(3.7	)		(2	)	(10.0	)		15		3.9			(4	)	(2.3	)
Change in estimates and interest related to uncertain and effectively settled tax positions		5		3.7			—		(0.7	)		(11	)	(2.9	)		10		5.5
Tax credits		(1	)	(0.7	)		(1	)	(6.0	)		(3	)	(0.8	)		(3	)	(1.6	)
Dividends on PHI shares held in retirement savings plan		(1	)	(0.7	)		—		(3.3	)		(2	)	(0.5	)		(2	)	(0.9	)
Release of deferred tax asset valuation allowance		—		—			—		—			—		—			(8	)	(4.4	)
Change in state deferred tax balances as a result of corporate restructuring		—		—			2		14.0			—		—			(6	)	(3.6	)
Asset removal costs		(2	)	(1.5	)		(1	)	(4.7	)		(4	)	(1.1	)		(2	)	(1.0	)
Adjustment to prior year taxes		—		—			—		(3.3	)		—		—			(1	)	(0.4	)
Deferred tax basis adjustments		—		—			(4	)	(28.7	)		1		0.3			—		(0.2	)
Other, net		4		2.6			(1	)	(4.3	)		(3	)	(0.8	)		(2	)	(1.1	)
Consolidated income tax expense related to continuing operations	$	55		40.7	%	$	(6	)	(40.0	)%	$	143		37.6	%	$	52		29.4	%

Three Months Ended September 30, 2011 and 2010

PHI’s consolidated effective tax rates from continuing operations for the three months ended September 30, 2011 and 2010 were 40.7% and (40.0)%, respectively. The increase in the effective tax rate was primarily due to the non-recurring benefit recorded in the third quarter of 2010 related to the 2010 corporate restructuring that impacted state tax expense and state deferred tax balances, the benefit of certain deferred tax basis adjustments recorded in 2010 and changes in estimates and interest related to uncertain and effectively settled tax positions.

In addition, as discussed further in Note (15) “Commitments and Contingencies—District of Columbia Tax Legislation,” the Fiscal Year 2012 Budget Support Act of 2011 (the Budget Support Act) became law during the third quarter of 2011. The Budget Support Act includes a provision that requires corporate taxpayers in

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the District of Columbia (the District) to calculate taxable income allocable or apportioned to the District by reference to the income and apportionment factors applicable to commonly controlled entities organized within the United States that are engaged in a unitary business. Previously, only the income of companies with direct nexus to the District was taxed. As a result of the change, during the third quarter of 2011, PHI recorded an additional state income tax expense of $2 million.

The deferred tax basis adjustments recorded in 2010 were the result of a $2 million adjustment to eliminate deferred tax liabilities associated with a goodwill impairment charge recorded in 2005, and the recording of a $2 million benefit related to deferred tax attributes.

Nine Months Ended September 30, 2011 and 2010

PHI’s consolidated effective tax rates from continuing operations for the nine months ended September 30, 2011 and 2010 were 37.6% and 29.4%, respectively. The increase in the effective tax rate was primarily due to the impact of the early termination of certain cross border energy leases and the non-recurring benefit recorded in the third quarter of 2010 related to the 2010 corporate restructuring that impacted state tax expense and state deferred tax balances. This increase was partially offset by interest benefits associated with the settlement with the Internal Revenue Service (IRS) discussed below (included in changes in estimates and interest related to uncertain and effectively settled tax positions).

As discussed further in Note (7), “Leasing Activities,” during the second quarter of 2011, PHI terminated early its interest in certain cross-border energy leases prior to the end of the stated term. As a result of the early terminations, PHI reversed $22 million of previously recognized Federal income tax benefits associated with those leases which will not be realized.

In the second quarter of 2011, PHI reached a settlement with the IRS with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that had been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, PHI has recorded an additional tax benefit in the amount of $17 million (after-tax). This additional interest income was recorded in the second quarter of 2011.

As discussed above, PHI also recorded additional state tax expense as a result of the District’s mandatory unitary combined reporting in the third quarter of 2011.

The 2010 effective tax rate also included the non-recurring impact of the April 2010 corporate restructuring. As a result of this restructuring, PHI recorded approximately $16 million of non-recurring tax benefits in 2010 including approximately $8 million resulting from a change in state apportionment factors and the release of $8 million of valuation allowances on deferred tax assets related to state net operating losses.

Also included in changes in estimates and interest related to uncertain and effectively settled tax positions for 2010 is $6 million of additional income tax expense related to erroneously recorded interest income for state tax purposes on uncertain and effectively settled tax positions as further discussed in Note (2), “Significant Accounting Policies—Income Tax Adjustments.”

(11)NON-CONTROLLING INTEREST

On February 25, 2011, ACE redeemed all of its outstanding cumulative preferred stock for approximately $6 million.

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(12) EARNINGS PER SHARE

PHI’s basic and diluted earnings per share (EPS) calculations are shown below:

	Three Months Ended  September 30,
	2011		2010
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	80	$	21
Net loss from discontinued operations		—		(4	)
Net income	$	80	$	17
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		226		224
Adjustment to shares outstanding		—		—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		226		224
Net effect of potentially dilutive shares (a)		—		—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		226		224
Basic and diluted earnings per share of common stock from continuing operations	$	0.35	$	0.09
Basic and diluted loss per share of common stock from discontinued operations		—		(0.01	)
Basic and diluted earnings per share	$	0.35	$	0.08

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS because they were anti-dilutive was 119,766 and 280,266 for the three months ended September 30, 2011 and 2010, respectively.

	Nine Months Ended September 30,
	2011		2010
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	237	$	125
Net income (loss) from discontinued operations		1		(126	)
Net income (loss)	$	238	$	(1	)
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		226		223
Adjustment to shares outstanding		—		—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		226		223
Net effect of potentially dilutive shares (a)		—		—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		226		223
Basic and diluted earnings per share of common stock from continuing operations	$	1.05	$	0.56
Basic and diluted loss per share of common stock from discontinued operations		—		(0.56	)
Basic and diluted earnings per share	$	1.05	$	—

(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 was 119,766 and 280,266 for the nine months ended September 30, 2011 and 2010, respectively.

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(13) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Derivatives are used by the Pepco Energy Services and Power Delivery segments to hedge commodity price risk, as well as by PHI, from time to time, to hedge interest rate risk.

The retail energy supply business of Pepco Energy Services, which is in the process of being wound down, enters into energy commodity contracts in the form of electricity and natural gas futures, swaps, options and forward contracts to hedge commodity price risk in connection with the purchase of physical natural gas and electricity for distribution to customers. The primary risk management objective is to manage the spread between retail sales commitments and the cost of supply used to service those commitments to ensure stable cash flows and lock in favorable prices and margins when they become available.

Pepco Energy Services’ commodity contracts that are not designated for hedge accounting, do not qualify for hedge accounting, or do not meet the requirements for normal purchase and normal sale accounting, are marked to market through current earnings. Forward contracts that meet the requirements for normal purchase and normal sale accounting are recorded on an accrual basis.

In the Power Delivery business, DPL uses derivative instruments in the form of swaps and over-the-counter options primarily to reduce gas commodity price volatility and to limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL also manages commodity risk with physical natural gas and capacity contracts that are not classified as derivatives. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered from its customers through a fuel adjustment clause approved by the DPSC.

PHI also uses derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt issued in connection with the operation of their businesses. In June 2002, PHI entered into several treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in August 2002. Upon issuance of the fixed rate-debt in August 2002, the treasury rate locks were terminated at a loss. The loss has been deferred in AOCL and is being recognized in income over the life of the debt issued as interest payments are made. As further described in Note (9), “Debt,” $15 million of these pre-tax losses ($9 million after-tax) were reclassified into income in the third quarter of 2010.

The tables below identify the balance sheet location and fair values of derivative instruments as of September 30, 2011 and December 31, 2010:

	As of September 30, 2011
Balance Sheet Caption	Derivatives Designated as Hedging Instruments (a)			Other Derivative Instruments (a)			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets)	$	22		$	20		$	42		$	(27	)	$	15
Derivative Assets (non-current assets)		—			2			2			(2	)		—
Total Derivative Assets		22			22			44			(29	)		15
Derivative Liabilities (current liabilities)		(72	)		(44	)		(116	)		83			(33	)
Derivative Liabilities (non-current liabilities)		(18	)		(11	)		(29	)		21			(8	)
Total Derivative Liabilities		(90	)		(55	)		(145	)		104			(41	)
Net Derivative (Liability) Asset	$	(68	)	$	(33	)	$	(101	)	$	75		$	(26	)

(a) Amounts included in Derivatives Designated as Hedging Instruments primarily consist of natural gas derivatives that were designated as cash flow hedges prior to the January 1, 2011 election to discontinue cash flow hedge accounting for these derivatives. Amounts included in Other Derivative Instruments primarily consist of gains or losses on natural gas derivatives that are not accounted for as cash flow hedges after the January 1, 2011 election to discontinue cash flow hedge accounting.

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	As of December 31, 2010
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative Assets (current assets)	$	40		$	43		$	83		$	(38	)	$	45
Derivative Assets (non-current assets)		16			3			19			(19	)		—
Total Derivative Assets		56			46			102			(57	)		45
Derivative Liabilities (current liabilities)		(125	)		(63	)		(188	)		122			(66	)
Derivative Liabilities (non-current liabilities)		(68	)		(10	)		(78	)		57			(21	)
Total Derivative Liabilities		(193	)		(73	)		(266	)		179			(87	)
Net Derivative (Liability) Asset	$	(137	)	$	(27	)	$	(164	)	$	122		$	(42	)

Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), PHI offsets the fair value amounts recognized for derivative instruments and the fair value amounts recognized for related collateral positions executed with the same counterparty under master netting agreements. The amount of cash collateral that was offset against these derivative positions is as follows:

	September 30, 2011		December 31, 2010
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	75	$	122

(a) Includes cash deposits on commodity brokerage accounts

As of September 30, 2011 and December 31, 2010, all PHI cash collateral pledged related to derivative instruments accounted for at fair value was entitled to offset under master netting agreements.

Derivatives Designated as Hedging Instruments

Cash Flow Hedges

Pepco Energy Services

For energy commodity contracts that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of AOCL and is reclassified into income in the same period or periods during which the hedged transactions affect income. Gains and losses on the derivative that are related to hedge ineffectiveness or the forecasted hedged transaction being probable not to occur, are recognized in income. Effective January 1, 2011, Pepco Energy Services elected to no longer apply cash flow hedge accounting to its natural gas derivatives. Amounts included in AOCL for natural gas cash flow hedges as of September 30, 2011 represent net losses on derivatives prior to the January 1, 2011 election to discontinue cash flow hedge accounting less amounts reclassified into income as the hedged transactions occur or because the hedged transactions were probable not to occur. Gains or losses on these natural gas derivatives after January 1, 2011 are recognized directly in income.

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Cash flow hedge activity during the three and nine months ended September 30, 2011 and 2010 is provided in the tables below:

	Three Months  Ended September 30,					Nine Months  Ended September 30,
	2011		2010			2011		2010
	(millions of dollars)
Amount of net pre-tax (loss) gain arising during the period included in accumulated other comprehensive loss	$	—	$	(38	)	$	2	$	(116	)
Amount of net pre-tax loss reclassified into income:
Effective portion:
Fuel and Purchased Energy		15		23			61		108
Ineffective portion:(a)
Revenue		1		—			1		2
Total net pre-tax loss reclassified into income		16		23			62		110
Net pre-tax gain (loss) on commodity derivatives included in accumulated other comprehensive loss	$	16	$	(15	)	$	64	$	(6	)

(a) For the three and nine months ended September 30, 2011, $1 million was reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur. For the three and nine months ended September 30, 2010, no amounts were reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur.

As of September 30, 2011 and December 31, 2010, Pepco Energy Services had the following types and quantities of outstanding energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.

	Quantities
Commodity	September 30, 2011		December 31, 2010
Forecasted Purchases Hedges
Natural gas (One Million British Thermal Units (MMBtu))		—		8,597,106
Electricity (Megawatt hours (MWh))		1,879,840		2,677,640
Electricity Capacity (MW-Days)		—		34,730
Forecasted Sales Hedges
Electricity (MWh)		991,840		2,517,200

Power Delivery

All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered from customers based on the fuel adjustment clause approved by the DPSC. The following table indicates the amount of the net unrealized derivative losses arising during the period included in regulatory assets and the realized losses recognized in the Consolidated Statements of Income for the three and nine months ended September 30, 2011 and 2010 associated with cash flow hedges:

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(millions of dollars)
Net Unrealized Losses arising during the period included in Regulatory Assets	$	(1	)	$	(3	)	$	(1	)	$	(9	)
Net Realized Losses Recognized in Fuel and Purchased Energy Expense		(2	)		(4	)		(5	)		(10	)

As of September 30, 2011 and December 31, 2010, DPL had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	September 30, 2011		December 31, 2010
Forecasted Purchases Hedges
Natural Gas (MMBtu)		942,500		1,670,000

Effective October 1, 2011, DPL elected to no longer apply cash flow hedge accounting to its natural gas derivatives. These derivatives will continue to be employed as part of DPL’s natural gas hedging activities under the hedging program approved by the DPSC, and their dedesignation as cash flow hedges will not result in a change to the financial statement presentation because all of DPL’s gains and losses on these derivatives are recoverable from customers through the fuel adjustment clause approved by the DPSC.

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

The tables below provide details regarding effective cash flow hedges included in PHI’s Consolidated Balance Sheet as of September 30, 2011 and 2010. Cash flow hedges are marked to market on the balance sheet with corresponding adjustments to AOCL for effective cash flow hedges. As of September 30, 2011, $31 million of the losses in AOCL were associated with natural gas derivatives that Pepco Energy Services previously designated as cash flow hedges. Although Pepco Energy Services no longer designates its natural gas derivatives as cash flow hedges effective January 1, 2011, gains or losses previously deferred in AOCL as of December 31, 2010 will remain in AOCL until the hedged forecasted transaction occurs unless it is probable that the hedged forecasted transaction will not occur. The data in the tables indicate the cumulative net loss after-tax related to effective cash flow hedges by contract type included in AOCL, the portion of AOCL expected to be reclassified to income during the next 12 months, and the maximum hedge or deferral term:

	As of September 30, 2011
Contracts	Accumulated Other Comprehensive  Loss After-tax (a)		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	(millions of dollars)
Energy Commodity (b)	$	40	$	28		32 months
Interest Rate		10		1		251 months
Total	$	50	$	29

(a) AOCL on PHI’s Consolidated Balance Sheet as of September 30, 2011, includes a $21 million balance related to minimum pension liability. This balance is not included in this table as the minimum pension liability is not a cash flow hedge.

(b) The unrealized energy commodity derivative losses recorded in AOCL are largely offset by forecasted natural gas and electricity physical purchases for delivery to retail customers that are in gain positions and subject to accrual accounting. These forward purchase contracts are exempted from mark-to-market accounting because they either qualify as normal purchases under FASB guidance on derivatives and hedging or they are not derivative contracts. Under accrual accounting, no asset is recorded on the balance sheet for these contracts, and the purchase cost is not recognized until the period of distribution.

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	As of September 30, 2010
Contracts	Accumulated Other Comprehensive Loss After-tax (a)		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	(millions of dollars)
Energy Commodity (b)	$	102	$	63		44 months
Interest Rate		11		1		263 months
Total	$	113	$	64

(a) AOCL on PHI’s Consolidated Balance Sheet as of September 30, 2010, includes a $15 million balance related to minimum pension liability and a $20 million balance related to Conectiv Energy. These balances are not included in this table as the minimum pension liability is not a cash flow hedge and Conectiv Energy is reported as a discontinued operation.

(b) The unrealized derivative losses recorded in AOCL are largely offset by forecasted natural gas and electricity physical purchases for delivery to retail customers that are in gain positions and subject to accrual accounting. These forward purchase contracts are exempted from mark-to-market accounting because they either qualify as normal purchases under FASB guidance on derivatives and hedging or they are not derivative contracts. Under accrual accounting, no asset is recorded on the balance sheet for these contracts, and the purchase cost is not recognized until the period of distribution.

Other Derivative Activity

Pepco Energy Services

Pepco Energy Services holds certain derivatives that are not in hedge accounting relationships nor are they designated as normal purchases or normal sales. These derivatives are recorded at fair value on the balance sheet with changes in fair value recorded through income.

For the three and nine months ended September 30, 2011 and 2010, the amount of the derivative gain (loss) for Pepco Energy Services recognized in income is provided in the table below:

	Three Months Ended September 30, 2011								Three Months Ended September 30, 2010
	Revenue			Fuel and Purchased Energy Expense		Total			Revenue		Fuel and Purchased Energy Expense		Total
	(millions of dollars)
Realized mark-to-market gains	$	1		$	—	$	1		$	1	$	—	$	1
Unrealized mark-to-market losses		(5	)		—		(5	)		—		—		—
Total net mark-to-market (losses) gains	$	(4	)	$	—	$	(4	)	$	1	$	—	$	1

	Nine Months Ended September 30, 2011								Nine Months Ended September 30, 2010
	Revenue			Fuel and Purchased Energy Expense		Total			Revenue		Fuel and Purchased Energy Expense		Total
	(millions of dollars)
Realized mark-to-market (losses) gains	$	(1	)	$	—	$	(1	)	$	2	$	—	$	2
Unrealized mark-to-market losses		(10	)		—		(10	)		—		—		—
Total net mark-to-market (losses) gains	$	(11	)	$	—	$	(11	)	$	2	$	—	$	2

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As of September 30, 2011 and December 31, 2010, Pepco Energy Services had the following net outstanding commodity forward contract quantities and net position on derivatives that did not qualify for hedge accounting:

	September 30, 2011				December 31, 2010
Commodity	Quantity		Net Position		Quantity		Net Position
Financial transmission rights (MWh)		432,399		Long		381,215		Long
Electric Capacity (MW—Days)		20,740		Long		2,265		Long
Electric (MWh)		814,776		Long		1,455,800		Long
Natural gas (MMBtu)		33,695,858		Long		45,889,486		Long

Power Delivery

DPL holds certain derivatives that are not in hedge accounting relationships nor are they designated as normal purchases or normal sales. These derivatives are recorded at fair value on the Consolidated Balance Sheets with the gain or loss for the change in fair value recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory liabilities or regulatory assets are recorded on the Consolidated Balance Sheets and the recognition of the derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause. For the three and nine months ended September 30, 2011 and 2010, the net unrealized derivative losses arising during the period included in regulatory assets and the net realized losses recognized in the Consolidated Statements of Income are provided in the table below:

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2011			2010			2011			2010
	(millions of dollars)
Net Unrealized Losses arising during the period included in Regulatory Assets	$	(4	)	$	(9	)	$	(6	)	$	(21	)
Net Realized Losses Recognized in Fuel and Purchased Energy Expense		(3	)		(5	)		(14	)		(18	)

As of September 30, 2011 and December 31, 2010, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	September 30, 2011				December 31, 2010
Commodity	Quantity		Net Position		Quantity		Net Position
Natural Gas (MMBtu)		5,433,500		Long		7,827,635		Long

Contingent Credit Risk Features

The primary contracts used by the Pepco Energy Services and Power Delivery segments for derivative transactions are entered into under the International Swaps and Derivatives Association Master Agreement (ISDA) or similar agreements that closely mirror the principal credit provisions of the ISDA. The ISDAs include a Credit Support Annex (CSA) that governs the mutual posting and administration of collateral security. The failure of a party to comply with an obligation under the CSA, including an obligation to transfer collateral security when due or the failure to maintain any required credit support, constitutes an event of default under the ISDA for which the other party may declare an early termination and liquidation of all transactions entered into under the ISDA, including foreclosure against any collateral security. In addition, some of the ISDAs have cross default provisions under which a default by a party under another commodity or derivative contract, or the breach by a party of another borrowing obligation in excess of a specified threshold, is a breach under the ISDA.

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Under the ISDA or similar agreements, the parties establish a dollar threshold of unsecured credit for each party in excess of which the party would be required to post collateral to secure its obligations to the other party. The amount of the unsecured credit threshold varies according to the senior, unsecured debt rating of the respective parties or that of a guarantor of the party’s obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on-balance sheet as well as those designated as normal purchases and normal sales that are accounted for off-balance sheet. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of Pepco Energy Services are usually guaranteed by PHI. The obligations of DPL are stand-alone obligations without the guaranty of PHI. If PHI’s or DPL’s credit rating were to fall below “investment grade,” the unsecured credit threshold would typically be set at zero and collateral would be required for the entire net loss position. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder.

The gross fair value of PHI’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit risk-related contingent features on September 30, 2011 and December 31, 2010, was $74 million and $156 million, respectively, before giving effect to the impact of a credit rating downgrade that would increase these amounts or offsetting transactions that are encompassed within master netting agreements that would alter these amounts. As of September 30, 2011, PHI had posted cash collateral of $5 million against the gross derivative liability resulting in a net liability of $69 million. As of December 31, 2010, PHI had not posted any cash collateral against the gross derivative liability. PHI’s net settlement amount in the event of a downgrade of PHI’s and DPL’s senior unsecured debt rating to below “investment grade” as of September 30, 2011 and December 31, 2010, would have been approximately $129 million and $182 million, respectively, after taking into consideration the master netting agreements. At September 30, 2011 and December 31, 2010, normal purchase and normal sale contracts in a loss position increased PHI’s obligation.

PHI’s primary sources for posting cash collateral or letters of credit are its credit facilities. At September 30, 2011 and December 31, 2010, the aggregate amount of cash plus borrowing capacity under the credit facilities available to meet the future liquidity needs of PHI and its subsidiaries totaled $1.4 billion and $1.2 billion, respectively, of which $547 million and $728 million, respectively, was available to Pepco Energy Services.

(14) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

PHI applies FASB guidance on fair value measurement and disclosures (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, 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. The guidance 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) and the lowest priority to unobservable inputs (level 3). PHI classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation 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, such as the New York Mercantile Exchange (NYMEX).

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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 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 and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

PHI’s level 2 derivative instruments primarily consist of electricity derivatives at September 30, 2011. Level 2 power swaps are priced at liquid trading hub prices or valued using the liquid hub prices plus a congestion adder that is calculated using historical regression analysis.

Executive deferred compensation plan assets consist of life insurance policies that are categorized as level 2 assets because they are priced based on the assets underlying the policies, which consist of short-term cash equivalents and fixed income securities that are priced using observable market data. The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.

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.

Derivative instruments categorized as level 3 include natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC and natural gas physical basis contracts held by Pepco Energy Services. The valuation of the options is based, in part, on internal volatility assumptions extracted from historical NYMEX prices over a certain period of time. The physical basis contracts are valued using liquid hub prices plus a congestion adder that is internally derived from historical data and experience.

Executive deferred compensation plan assets and liabilities that are classified as level 3 include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies, which does not represent a quoted price in an active market.

The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities (excluding Conectiv Energy assets and liabilities held for sale) that were accounted for at fair value on a recurring basis as of September 30, 2011 and December 31, 2010. As required by the guidance, 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 the exercise of 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 September 30, 2011
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments (b)
Electricity (c)	$	5	$	—	$	5	$	—
Natural Gas (d)		2		—		—		2
Cash equivalents
Treasury Fund		113		113		—		—
Executive deferred compensation plan assets
Money Market Funds		18		18		—		—
Life Insurance Contracts		60		—		43		17
	$	198	$	131	$	48	$	19
LIABILITIES
Derivative instruments (b)
Electricity (c)	$	41	$	—	$	41	$	—
Natural Gas (d)		66		46		1		19
Capacity		1		—		1		—
Executive deferred compensation plan liabilities
Life Insurance Contracts		29		—		29		—
	$	137	$	46	$	72	$	19

(a) There were no significant transfers of instruments between level 1 and level 2 valuation categories.

(b) The fair value of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

(c) Represents wholesale electricity futures and swaps that are used mainly as part of Pepco Energy Services’ retail energy supply business.

(d) Level 1 instruments represent wholesale gas futures and swaps that are used mainly as part of Pepco Energy Services’ retail energy supply business and level 3 instruments primarily represent natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

	Fair Value Measurements at December 31, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Derivative instruments (b)
Electricity (c)	$	22	$	—	$	22	$	—
Cash equivalents
Treasury Fund		17		17		—		—
Executive deferred compensation plan assets
Money Market Funds		9		9		—		—
Life Insurance Contracts		66		—		47		19
	$	114	$	26	$	69	$	19
LIABILITIES
Derivative instruments (b)
Electricity (c)	$	88	$	—	$	88	$	—
Natural Gas (d)		98		75		—		23
Executive deferred compensation plan liabilities
Life Insurance Contracts		30		—		30		—
	$	216	$	75	$	118	$	23

(a) There were no significant transfers of instruments between level 1 and level 2 valuation categories.

(b) The fair value of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

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(c) Represents wholesale electricity futures and swaps that are used mainly as part of Pepco Energy Service’s retail energy supply business.

(d) Level 1 instruments represent wholesale gas futures and swaps that are used mainly as part of Pepco Energy Service’s retail energy supply business and level 3 instruments represent natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (level 3) for the nine months ended September 30, 2011 and 2010 are shown below:

	Nine Months Ended September 30, 2011
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(23	)	$	19
Total gains or (losses) (realized and unrealized)
Included in income		—			5
Included in accumulated other comprehensive loss		—			—
Included in regulatory assets		(6	)		—
Purchases		—			—
Issuances		—			(3	)
Settlements		11			(4	)
Transfers in (out) of level 3		1			—
Ending balance as of September 30	$	(17	)	$	17

	Nine Months Ended September 30, 2010
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(29	)	$	19
Total gains or (losses) (realized and unrealized)
Included in income		—			3
Included in accumulated other comprehensive loss		—			—
Included in regulatory assets		(21	)		—
Purchases		—			—
Issuances		—			(3	)
Settlements		18			—
Transfers in (out) of level 3		—			—
Ending balance as of September 30	$	(32	)	$	19

The breakdown of realized and unrealized gains or (losses) on level 3 instruments included in income as a component of “Other income” or “Other operation and maintenance” expense for the periods below were as follows:

	Nine Months Ended September 30,
	2011		2010
	(millions of dollars)
Total gains included in income for the period	$	5	$	3
Change in unrealized gains relating to assets still held at reporting date	$	2	$	3

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Other Financial Instruments

The estimated fair values of PHI’s issued debt and equity instruments at September 30, 2011 and December 31, 2010 are shown below:

	September 30, 2011				December 31, 2010
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	3,866	$	4,520	$	3,665	$	4,045
Transition Bonds issued by ACE Funding		343		392		367		406
Long-Term Project Funding		18		18		19		19
Redeemable Serial Preferred Stock		—		—		6		5

The fair value of Long-Term Debt issued by PHI and its utility subsidiaries was based on actual trade prices as of September 30, 2011 and December 31, 2010. Where trade prices were not available, PHI used a discounted cash flow model and other valuation methodologies deemed appropriate by management to estimate fair value. The fair value of Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on actual trade prices as of September 30, 2011. Bid prices obtained from brokers and validated by PHI were used at December 31, 2010, because actual trade prices were not available.

The fair value of the Redeemable Serial Preferred Stock was derived based on quoted market prices.

The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.

(15) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

District of Columbia Divestiture Case

In June 2000, the District of Columbia Public Service Commission (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 in 2000. This approval left unresolved issues of (i) 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 and (ii) whether Pepco was entitled to deduct certain costs in determining the amount of proceeds to be shared.

In May 2010, the DCPSC issued an order addressing all of the remaining issues related to the sharing of the proceeds of Pepco’s divestiture of its generating assets. In the order, the DCPSC ruled that Pepco is not required to share EDIT and ADITC with customers. However, the order also disallowed certain items that Pepco had included in the costs deducted from the proceeds of the sale of the generation assets. The disallowance of these costs, together with interest on the disallowed amount, increased the aggregate amount Pepco was required to distribute to customers, pursuant to the sharing formula, by approximately $11 million, which Pepco recognized as an expense in 2010 and refunded the amounts to its customers. In June 2010, Pepco filed an application for reconsideration of the DCPSC’s order. In July 2010, the DCPSC denied Pepco’s application for reconsideration. In September 2010, Pepco filed an appeal of the DCPSC’s decision with the

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District of Columbia Court of Appeals. On April 12, 2011, the Court of Appeals affirmed the DCPSC order. Pepco does not intend to appeal this decision.

Maryland Public Service Commission Reliability Investigation

In August 2010, following major storm events that occurred in July and August 2010, the Maryland Public Service Commission (MPSC) initiated a proceeding for the purpose of investigating the reliability of the Pepco distribution system and the quality of distribution service Pepco is providing its customers. On February 10, 2011, the MPSC issued a notice identifying as possible remedies the imposition of civil penalties, changes in the manner of Pepco’s operations, modification of Pepco’s service territory and revocation of Pepco’s authority to exercise its public utility franchise. Pepco’s position in this proceeding is that while it is implementing a comprehensive program that will improve the reliability of its distribution system and its planning for, and response to, adverse weather events, there is no evidentiary support to impose sanctions for past performance. The other parties, including the staff of the MPSC, the Maryland Office of People’s Counsel, the Maryland Energy Administration, and Montgomery County, Maryland, contend that Pepco’s service reliability has not met an acceptable level and have recommended a variety of sanctions, including, but not limited to, the imposition of significant fines, the denial of rate recovery for reliability improvement costs, a reduction in Pepco’s return on equity (ROE), restrictions on dividends to PHI in order to fund reliability improvement costs, compliance with enhanced reliability requirements within a specified period and various reporting requirements. While Pepco is committed to improving the reliability of its electric service, it is vigorously opposing the imposition of the sanctions requested by the other parties, which Pepco believes are unsupported by the record in this case. Pepco is unable to predict the outcome of this proceeding at this time.

Rate Proceedings

Over the last several years, PHI’s utility subsidiaries have proposed in each of their respective service territories the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date:

• A bill stabilization adjustment (BSA) has been approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia. The MPSC has initiated a proceeding to review how the BSA operates in Maryland to recover revenues lost as a result of major storm outages (as discussed below).

• A modified fixed variable rate design (MFVRD) has been approved in concept for DPL electric service in Delaware, but the implementation has been deferred by the DPSC pending the development of an implementation plan and a customer education plan. DPL anticipates that the MFVRD will be in place for electric service by early 2013.

• A MFVRD has been approved in concept for DPL natural gas service in Delaware, but implementation likewise has been deferred until development of an implementation plan and a customer education plan. DPL anticipates that the MFVRD will be in place for natural gas service by early 2013.

• In New Jersey, a BSA proposed by ACE as part of a Phase 2 to the base rate proceeding filed in August 2009 was not included in the final settlement approved by the NJBPU on May 16, 2011. Accordingly, there is no BSA proposal currently pending in New Jersey.

Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The MFVRD approved in concept in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric

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consumption) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, PHI views the MFVRD as an appropriate distribution revenue decoupling mechanism.

On February 1, 2011, the MPSC initiated proceedings involving Pepco and DPL, as well as unaffiliated utilities including Baltimore Gas & Electric Company and Southern Maryland Electric Cooperative, for the purpose of reviewing how the BSA operates to recover revenues lost as a result of major storm outages. In its orders initiating the proceedings, the MPSC expressed concern that the utilities’ respective BSAs may be allowing them to recover revenues lost during extended outages, therefore unintentionally eliminating an incentive to restore service quickly. The MPSC will consider whether the BSA, as currently in effect, is appropriate, whether the calculations or determinant factors for calculating the BSA should be modified, and if so, what modifications should be made. On July 22, 2011, the MPSC held a legislative-style hearing on this matter. A provision that excludes revenues lost as a result of major storm outages from the calculation of future BSA adjustments is already included in the BSA for Pepco in the District of Columbia as approved by the DCPSC. If the MPSC were to implement a change similar to the provision in effect in the District of Columbia, the financial impact of service interruptions due to a major storm would generally depend on the scope and duration of the outages. The potential financial impact of any modification to the BSA cannot be assessed until the details of the modification are known.

Delaware

DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover gas procurement costs through customer rates. In August 2010, DPL made its 2010 GCR filing, which proposes rates that would allow DPL to recover an amount equal to a two-year amortization of currently under-recovered gas costs. In October 2010, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2010, subject to refund and pending final DPSC approval. The effect of the proposed two-year amortization upon rates is an increase of 0.1% in the level of GCR. The parties in the proceeding submitted a proposed settlement to the hearing examiner on June 3, 2011, which includes the first year of DPL’s two-year amortization but provides that DPL will forego the interest (a total of $342,000 for the two-year period 2011-2013) associated with that amortization. The proposed settlement was approved by the DPSC on October 18, 2011.

In August 2011, DPL made its 2011 GCR filing. The filing includes the second year of the effect of the proposed two-year amortization as proposed in DPL’s 2010 filing. On September 20, 2011, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2011, subject to refund and pending final DPSC approval.

In July 2010, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. As subsequently amended, the filing sought approval of an annual rate increase of approximately $10.2 million, assuming the implementation of the MFVRD, based on a requested ROE of 11.00%. As permitted by Delaware law, DPL placed an annual increase of approximately $2.5 million into effect, on a temporary basis, on August 31, 2010, and the remainder of approximately $7.7 million of the requested increase was placed into effect on February 2, 2011, in each case subject to refund and pending final DPSC approval. On June 21, 2011, the DPSC approved a settlement providing for an annual rate increase of approximately $5.8 million, based on an ROE of 10% (which was memorialized in an order issued August 9, 2011). The decision deferred the implementation of the MFVRD until an implementation plan and a customer education plan are developed. As of September 30, 2011, the amount collected in excess of the approved rate has been refunded to customers through a bill credit.

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District of Columbia

On July 8, 2011, Pepco filed an application with the DCPSC to increase its electric distribution base rates by approximately $42 million annually, based on an ROE of 10.75%. A decision by the DCPSC is expected in the second quarter of 2012.

Maryland

On December 21, 2010, DPL filed an application with the MPSC to increase its electric distribution base rates by $17.8 million annually, based on an ROE of 10.75%. On May 25, 2011, DPL and the other parties to the proceeding filed a unanimous stipulation and settlement providing for a rate increase of approximately $12.2 million and proposing a Phase II proceeding to explore methods to address the issue of regulatory lag (which is the delay experienced by DPL in recovering increased costs in its distribution rate base). Although no ROE was specified in the proposed settlement, it did provide that the ROE for purposes of calculating the allowance for funds used during construction and regulatory asset carrying costs would remain unchanged. The current ROE for those items is 10%. On July 8, 2011, the MPSC approved the proposed settlement. On October 17, 2011, the parties notified the MPSC that they were unable to reach an agreement on the regulatory lag issues in the Phase II proceeding. DPL will pursue a regulatory lag mitigation mechanism in its upcoming rate case filing.

New Jersey

On August 5, 2011, ACE filed a petition with the NJBPU to increase its electric distribution rates by the net amount of approximately $58.9 million, based on a return on equity of 10.75%. The net increase consists of a rate increase proposal of approximately $70.5 million, less a deduction from base rates of approximately $17 million attributable to excess depreciation expenses, plus approximately a $4.9 million increase in sales-and-use taxes and an upward adjustment of approximately $0.5 million in the Regulatory Asset Recovery Charge. ACE has requested that the rate increase be effective in May 2012.

In July 2009, the NJBPU approved certain rate recovery mechanisms in connection with ACE’s Infrastructure Investment Program (the IIP). In exchange for the increase in infrastructure investment, the NJBPU, through the IIP, allowed recovery of ACE’s infrastructure investment capital expenditures through a special rate outside the normal rate recovery mechanism of a base rate filing. The IIP is designed to stimulate the New Jersey economy and provide incremental employment in ACE’s service territory by increasing the level of infrastructure expenditures invested above otherwise normal budgeted levels. On October 18, 2011, ACE filed a petition with the NJBPU for approval of an extension and expansion to the IIP, which is intended to become effective on or about January 1, 2012, and remain in effect until December 31, 2014. In calendar year 2012, ACE proposes as part of the IIP to recover approximately $69 million in reliability-related capital expenditures out of total reliability-related annual capital expenditures of approximately $103 million. For calendar years 2013 and 2014, ACE proposes to recover IIP capital expenditures of approximately $94 million and $81 million, respectively. Capital expenditures related to the proposed special rate would be subject to annual reconciliation and approval by the NJBPU.

On August 26, 2011, ACE filed a petition with the NJBPU seeking authorization for deferred accounting treatment of uninsured incremental storm damage restoration costs not otherwise recovered through base rates. In this petition, ACE proposed that storm costs for each individual storm would qualify for deferred accounting if the storm causes disruption to service of 10% or more of ACE’s customers or if any of ACE’s customers are without utility service for more than 24 hours. The deferred accounting treatment would include recovery of such costs incurred during Hurricane Irene, which impacted ACE’s service territory in the third quarter of 2011.

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Retained Environmental Exposures from the Sale of the Conectiv Energy Wholesale Power Generation Business

On July 1, 2010, PHI sold the Conectiv Energy wholesale power generation business to Calpine. Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. PHI is obligated to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to preliminary estimates, the costs of ISRA-required remediation activities at the nine generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million. PHI has accrued approximately $4 million as of September 30, 2011 for the ISRA-required remediation activities at the nine generating facility sites.

The sale of the Conectiv Energy wholesale power generation business to Calpine did not include a coal ash landfill site located at the Edge Moor generating facility, which PHI intends to close. The preliminary estimate of the costs to PHI to close the coal ash landfill ranges from approximately $2 million to $3 million, plus annual post-closure operations, maintenance and monitoring costs, estimated to range between $120,000 and $193,000 per year for 30 years. As of September 30, 2011, PHI had accrued approximately $5 million for landfill closure and monitoring.

On September 14, 2011, PHI received a request for data from the U.S. Environmental Protection Agency (EPA) regarding operations at the Deepwater generating facility in New Jersey (which was included in the sale to Calpine) between January 1, 2001 and July 1, 2010, to demonstrate compliance with the Clean Air Act’s new source review permitting program. In subsequent discussions, EPA agreed to limit the time period for which it is seeking data to February 2004 to July 1, 2010. Under the terms of the Calpine sale, PHI is obligated to indemnify Calpine for any failure of PHI, on or prior to the closing date of the sale, to comply with environmental laws attributable to the construction of new, or modification of existing, sources of air emissions. At this time, PHI does not expect this inquiry to have a material effect on its financial position or results of operations.

General Litigation

In 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.

As of September 30, 2011, there are approximately 180 cases still pending against Pepco in the Maryland State Courts, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant Corporation (Mirant) for defense and indemnification in connection with the sale by Pepco of 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. If an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco’s and PHI’s financial condition, results of operations and cash flows.

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Environmental Litigation

PHI, through its subsidiaries, is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. 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.

Franklin Slag Pile Site. In November 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983. EPA claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA letter also states that, as of the date of the letter, EPA’s expenditures for response measures at the site have exceeded $6 million. EPA estimates the cost for future response measures will be approximately $6 million. ACE believes that EPA sent similar general notice letters to three other companies and various individuals.

ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications and, therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE. Costs to resolve this matter are not expected to be material and are expensed as incurred.

Peck Iron and Metal Site. EPA informed Pepco in a May 2009 letter that Pepco may be a PRP under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that Peck’s metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by former Peck Iron and Metal personnel, who informed EPA that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales may be entitled to the recyclable material exemption from CERCLA liability. In a Federal Register notice published on November 4, 2009, EPA placed the Peck Iron and Metal site on the National Priorities List (NPL). The NPL, among other things, serves as a guide to EPA in determining which sites warrant further investigation to assess the nature and extent of the human health and environmental risks associated with a site. In a July 12, 2011 letter, EPA invited Pepco to enter into discussions with the agency to conduct a remedial investigation/feasibility study (RI/FS) at the site. Pepco is evaluating EPA’s invitation, but cannot at this time predict the costs of the RI/FS, the cost of performing a remedy at the site or the amount of such costs that EPA might seek to impose on Pepco.

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Ward Transformer Site. In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including ACE, DPL and Pepco with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. With input from the court, the parties are discussing the next step in the litigation, which is likely to be the filing of summary judgment motions regarding liability for certain “test case” defendants other than ACE, DPL and Pepco. The case is expected to be stayed as to the remaining defendants pending rulings upon the test cases. Although the magnitude of the potential liability at this site is not known at this time, PHI does not believe that any of its three utility subsidiaries had extensive business transactions, if any, with the Ward Transformer site and therefore, costs incurred to resolve this matter are not expected to be material.

Benning Road Site. In September 2010, PHI received a letter from EPA stating that EPA and the District of Columbia Department of the Environment (DDOE) have identified the Benning Road location, consisting of a transmission and distribution facility operated by Pepco and a generation facility operated by Pepco Energy Services, as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The letter stated that the principal contaminants of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons, that EPA is monitoring the efforts of DDOE and that EPA intends to use federal authority to address the Benning Road site if an agreement for a comprehensive study to evaluate (and, if necessary, to clean up) the facility is not reached.

In January 2011, Pepco and Pepco Energy Services entered into a proposed consent decree with DDOE that requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10-15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for DDOE’s selection of a remedial action for the Benning Road site and for the Anacostia River sediment associated with the site. In February 2011, the District filed a complaint against Pepco and Pepco Energy Services in the United States District Court for the District of Columbia for the purpose of obtaining judicial approval of the consent decree. The complaint asserted claims under CERCLA, the Resource Conservation and Recovery Act, and District of Columbia law seeking to compel Pepco and Pepco Energy Services to take actions to investigate and clean up contamination allegedly originating from the Benning Road site, and to reimburse the District for its response costs. The filing of this complaint was not intended to lead to active litigation. Rather, after receiving public comment on the proposed consent decree, DDOE planned to file a motion requesting the District Court to enter the consent decree. In March 2011, Anacostia Riverkeeper, Inc., the Anacostia Watershed Society and the Natural Resources Defense Council (collectively, the Environmental Organizations) submitted comments to DDOE objecting to the proposed consent decree on several grounds. In April 2011, while DDOE was preparing its response to comments received on the proposed consent decree, the Environmental Organizations filed a motion to intervene as plaintiffs in the District Court action. Pepco and Pepco Energy Services and DDOE have filed briefs opposing their intervention motion. In August, DDOE, Pepco and Pepco Energy Services agreed to certain revisions to the consent decree to address some of the comments from the Environmental Organizations. On September 1, 2011, DDOE filed a motion asking the District Court to enter the revised consent decree (and at the same time deny the Environmental Organizations’ motion to intervene). Briefing is complete on the motion to intervene and the motion to enter the consent decree. These motions are ready for decision by the District Court, but no decision has yet been issued. If the District Court allows the Environmental Organizations to intervene and become parties to the litigation, the settlement of the litigation by means of the consent decree will require their agreement, which could require changes to the terms of the consent decree – including the nature and scope of the work required to be performed by Pepco and Pepco Energy Services. Work on the RI/FS is not expected to begin until this matter is resolved.

At the present time, in light of the efforts by DDOE, Pepco and Pepco Energy Services to address the site through the proposed consent decree, Pepco and Pepco Energy Services anticipate that EPA will continue to refrain from listing the Benning Road facility on the NPL. The current estimate of the costs for performing

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the RI/FS is approximately $1 million. The remediation costs cannot be determined until the RI/FS is completed and the nature and scope of any remedial action are defined. However, the remediation costs are preliminarily projected to be approximately $13 million. As of September 30, 2011, PHI had an accrued liability of approximately $14 million with respect to this matter.

Price’s Pit Site. ACE owns a transmission and distribution right-of-way that traverses the Price’s Pit superfund site in Egg Harbor Township, New Jersey. EPA placed Price’s Pit on the NPL in 1983 and the New Jersey Department of Environmental Protection (NJDEP) undertook an environmental investigation to identify and implement remedial action at the site. NJDEP’s investigation revealed that landfill waste had been disposed on ACE’s right-of-way and NJDEP determined that ACE was a responsible party as the owner of a facility on which a hazardous substance has been deposited. ACE, EPA and NJDEP entered into a settlement agreement effective on August 11, 2011 to resolve ACE’s alleged liability. The settlement agreement requires ACE to make a payment of approximately $1 million (the amount accrued by ACE in 2010) to the EPA Hazardous Substance Superfund, which has been paid, and donate a four-acre parcel of land adjacent to the site to NJDEP.

Indian River Oil Release. In 2001, DPL entered into a consent agreement with the Delaware Department of Natural Resources and Environmental Control for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination resulting from an oil release at the Indian River generating facility, which was sold in June 2001. As of September 30, 2011, DPL’s accrual for expected future costs to fulfill its obligations under the consent agreement was approximately $5 million, of which approximately $1 million is expected to be incurred during the remainder of 2011.

Potomac River Mineral Oil Release. On January 23, 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at Pepco’s Potomac River substation in Alexandria, Virginia. An overflow of an underground secondary containment reservoir resulted in approximately 4,500 gallons of mineral oil flowing into the Potomac River.

The release falls within the regulatory jurisdiction of multiple federal and state agencies. Beginning in March 2011, DDOE issued a series of compliance directives that require Pepco to prepare an incident report, provide certain records, and prepare and implement plans for sampling surface water and river sediments and assessing ecological risks and natural resources damages. Pepco has submitted the requested incident report and provided the requested records and on October 21, 2011, received DDOE approval of Pepco’s work plans for the sampling and assessment work.

On March 16, 2011, the Virginia Department of Environmental Quality (VADEQ) requested documentation regarding the release and the preparation of an emergency response report, which Pepco submitted to the agency on April 20, 2011. On March 25, 2011, Pepco received a notice of violation from VADEQ and in August 2011, Pepco executed a consent agreement with VADEQ pursuant to which Pepco will be obligated to pay a civil penalty of approximately $40,000. The consent agreement states that VADEQ has determined that no further action is necessary to remediate the mineral oil spill at the facility (although DDOE retains jurisdiction to require further response actions to assess possible impacts to the river). The Virginia State Water Control Board is expected to approve the consent agreement at its December 2011 meeting, after which it will be executed by VADEQ.

During March 2011, EPA conducted an inspection of the Potomac River substation to review compliance with federal regulations regarding Spill Prevention, Control, and Countermeasure (SPCC) plans for facilities using oil-containing equipment in proximity to surface waters. Following the inspection, EPA advised Pepco that it had identified several potential violations of the SPCC regulations relating to SPCC plan content, recordkeeping, and secondary containment, which may lead to an EPA demand for noncompliance penalties. As a result of the oil release, Pepco submitted a revised SPCC plan to EPA on August 18, 2011. Pepco also implemented certain changes to the existing containment systems at the facility on an interim basis in

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accordance with the revisions to the SPCC plan, and is evaluating certain permanent changes to the containment systems. During the third quarter of 2011, a study performed by PHI estimated the remediation costs at, and PHI accrued, approximately $1 million.

The U.S. Coast Guard has assessed a $5,000 penalty against Pepco for the release of oil into the waters of the United States, which Pepco has paid.

The amount of penalties, if any, that may be imposed by DDOE and/or EPA and the costs associated with possible additional changes to the containment system, possible additional response actions, or possible natural resource damage claims cannot be estimated at this time; however, based on current information, PHI and Pepco do not believe this matter will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

Fauquier County Landfill Site.On October 7, 2011, Pepco Energy Services received a notice of violation dated October 5, 2011, from the VADEQ, which advised Pepco Energy Services of information on which VADEQ may rely to institute an administrative or judicial enforcement action in connection with alleged violation of Virginia air pollution control law and regulations at the facility of Pepco Energy Services’ subsidiary Fauquier County Landfill Gas, LLC in Warrenton, Virginia. The notice of violation is based on an on-site VADEQ inspection during which VADEQ observed certain alleged deficiencies relating to the facility’s permit to construct and operate. The notice of violation invited Pepco Energy Services to discuss the alleged deficiencies and indicated that Pepco Energy Services may be asked to enter into a consent order to formalize a plan and schedule of corrective action along with the assessment of civil charges. Pepco Energy Services is scheduled to meet with VADEQ on November 29, 2011. The amount of penalties, if any, that may be imposed by VADEQ cannot be predicted at this time; however, based on information currently known, Pepco Energy Services does not believe this matter will have a material adverse effect on its financial condition, results of operations or cash flows.

PHI’s Cross-Border Energy Lease Investments

Between 1994 and 2002, 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 comprised of multiple leases and the investment is structured as a sale and leaseback transaction commonly referred to by the IRS as a sale-in/lease-out or SILO transaction. PHI had previously received annual tax benefits from these eight cross-border energy lease investments of approximately $56 million, which as of March 31, 2011, had an aggregate book value of approximately $1.4 billion.

As more fully discussed in Note (7), “Leasing Activities,” PHI entered into early termination agreements with two lessees, at their request, with respect to all of the leases comprising one cross-border energy lease investment and a small portion of the leases comprising another cross-border energy lease investment in the second quarter of 2011. PHI received net cash proceeds of $161 million (net of a termination payment of $423 million used to retire the non-recourse debt associated with the terminated leases) and recorded a pre-tax gain of $39 million, representing the excess of the net cash proceeds over the carrying value of the lease investments. Going forward, PHI anticipates that it will receive annual tax benefits from these lease investments of approximately $52 million. As of September 30, 2011, the book value of PHI’s investment in its cross-border energy lease investments was approximately $1.3 billion. After taking into consideration the $74 million paid with the 2001-2002 audit (as discussed below), the net federal and state tax benefits received for the remaining leases from January 1, 2001, the earliest year that remains open to audit, to September 30, 2011, has been approximately $499 million.

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Since 2005, PHI’s cross-border energy lease investments have been under examination by the IRS as part of the PHI federal income tax audits. In connection with the audit of PHI’s 2001-2002 and 2003-2005 income tax returns, respectively, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to each of its cross-border energy lease investments. In addition, the IRS has sought to recharacterize each of the leases as a loan transaction as to which PHI would be subject to original issue discount income. PHI disagrees with the IRS’ proposed adjustments and in August 2006 and May 2009 filed protests of these findings with the Office of Appeals of the IRS. Effective November 2010, PHI entered into a settlement agreement with the IRS for the 2001 and 2002 tax years and subsequently filed refund claims for the disallowed tax deductions relating to the leases for these years. Earlier this year, as part of this settlement, PHI paid $74 million of additional tax for 2001 and 2002, penalties of $1 million, and $28 million in interest associated with the disallowed deductions. PHI expects the IRS to deny its refund claims, and if so, PHI intends to pursue litigation against the IRS in the U.S. Court of Federal Claims to defend its tax position and recover the tax payment, interest and penalties. The IRS has up to six months (until January 2012) to act on the refund claim. Absent a settlement, any litigation against the IRS may take several years to resolve. The 2003-2005 income tax return review continues to be in process with the IRS Office of Appeals and at present, will not be a part of any U.S. Court of Federal Claims litigation discussed above.

At September 30, 2011, PHI modified its tax cash flow assumptions for two of the investments in the lease portfolio associated with the change in tax laws in the District of Columbia. Accordingly, PHI recalculated the equity investment and recorded a $7 million pre-tax ($3 million after-tax) charge.

At December 31, 2010, PHI modified its tax cash flow assumptions under its cross-border energy lease investments for the periods 2010-2013, to reflect the anticipated timing of potential litigation with the IRS concerning the investments. As a result of the 2010 recalculation, PHI recorded a $1 million after-tax non-cash charge to earnings at December 31, 2010.

In the event that the IRS were to be successful in disallowing 100% of the tax benefits associated with these leases and recharacterizing these leases as loans, PHI estimates that, as of September 30, 2011, it would be obligated to pay approximately $628 million in additional federal and state taxes and $116 million of interest on the remaining leases. The $628 million in additional federal and state taxes is net of the $74 million tax payment made in January 2011. In addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due.

PHI anticipates that any additional taxes that it would be required to pay as a result of the disallowance of prior deductions or a re-characterization of the leases as loans would be recoverable in the form of lower taxes over the remaining terms of the affected leases. Moreover, the entire amount of any additional federal and state tax would not be due immediately, but rather, the federal and state taxes would be payable when the open audit years are closed and PHI amends subsequent tax returns not then under audit. To mitigate the taxes due in the event of a total disallowance of tax benefits, PHI could elect to liquidate all or a portion of its seven remaining cross-border energy lease investments, which PHI estimates could be accomplished over a period of six months to one year. Based on current market values, PHI estimates that liquidation of the remaining portfolio would generate sufficient cash proceeds to cover the estimated $744 million in federal and state taxes and interest due as of September 30, 2011, in the event of a total disallowance of tax benefits and a recharacterization of the leases as loans. If payments of additional taxes and interest preceded the receipt of liquidation proceeds, the payments would be funded by currently available sources of liquidity.

To the extent that PHI does not prevail in this matter and suffers a disallowance of the tax benefits and incurs imputed original issue discount income, PHI would be required under FASB guidance on leases (ASC 840) to recalculate the timing of the tax benefits generated by the cross-border energy lease investments and adjust the equity value of the investments, which would result in a non-cash charge to earnings.

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District of Columbia Tax Legislation

On June 14, 2011, the Council of the District of Columbia approved the Budget Support Act of 2011. The Budget Support Act includes a provision requiring that corporate taxpayers in the District calculate taxable income allocable or apportioned to the District by reference to the income and apportionment factors applicable to commonly controlled entities organized within the United States that are engaged in a unitary business. This new reporting method was enacted on September 14, 2011 and is effective for tax years beginning on or after December 31, 2010. This new tax reporting method is reflected in PHI’s consolidated results of operations, as further discussed in Note (7), “Leasing Activities,” and Note (10), “Income Taxes.”

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

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

As of September 30, 2011, 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:

	Guarantor
	PHI		DPL		ACE		Pepco		Total
Energy procurement obligations of Pepco Energy Services (a)	$	170	$	—	$	—	$	—	$	170
Guarantees associated with disposal of Conectiv Energy assets (b)		28		—		—		—		28
Guaranteed lease residual values (c)		2		5		3		3		13
Total	$	200	$	5	$	3	$	3	$	211

(a) Pepco Holdings has contractual commitments for performance and related payments of Pepco Energy Services to counterparties under routine energy sales and procurement obligations.

(b) Represents guarantees by PHI in connection with transfers of Conectiv Energy tolling agreements and derivatives portfolio. The tolling agreement guarantees cover the payment by the entity to which the tolling agreement was assigned. The guaranteed amounts on the transferred tolling agreements totaled $15 million at September 30, 2011, which decline until the termination of the guarantees. The derivative portfolio guarantee is currently $13 million and covers Conectiv Energy’s performance prior to the assignment. This guarantee will remain in effect until the end of 2015.

(c) Subsidiaries of Pepco Holdings have guaranteed residual values in excess of fair value of certain equipment and fleet vehicles held through lease agreements. As of September 30, 2011, obligations under the guarantees were approximately $13 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 immaterial. As such, Pepco Holdings believes the likelihood of payments being required under the guarantee is remote.

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.

Energy Savings Performance Contracts

Pepco Energy Services has a diverse portfolio of energy savings performance contracts that are associated with the installation of energy savings equipment for federal, state and local government customers. As part of those contracts, Pepco Energy Services typically guarantees that the equipment or systems installed by

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Pepco Energy Services will generate a specified amount of energy savings on an annual basis over a multi-year period. As of September 30, 2011, Pepco Energy Services’ energy savings guarantees on both completed projects and projects under construction totaled $422 million over the life of the performance contracts with the longest remaining term being 15 years. On an annual basis, Pepco Energy Services undertakes a measurement and verification process to determine the amount of energy savings for the year and whether there is any shortfall in the annual energy savings compared to the guaranteed amount. Pepco Energy Services recognizes a liability for the value of the estimated energy savings shortfall when it is probable that the guaranteed energy savings will not be achieved and the amount is reasonably estimable. As of September 30, 2011, Pepco Energy Services did not have an accrued liability for energy savings performance contracts. There was no significant change in the type of contracts issued for the three and nine months ended September 30, 2011. Based on its historical experience, Pepco Energy Services believes the probability of incurring a material loss under its energy savings performance contracts is remote.

Dividends

On October 27, 2011, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable December 30, 2011, to shareholders of record on December 12, 2011.

(16)DISCONTINUED OPERATIONS

In 2010, the Board of Directors of Pepco Holdings approved a plan for the disposition of Conectiv Energy Holding Company. The plan consisted of the sale of the wholesale power generation business, which was completed on July 1, 2010, and the liquidation of all of Conectiv Energy’s remaining assets and businesses, which has been substantially completed. As a result of the plan of disposition, Conectiv Energy’s results of operations for the 2011 and 2010 quarterly and year-to-date periods are reported as discontinued operations.

PHI is reporting the results of operations of the former Conectiv Energy segment in discontinued operations in all periods presented in the accompanying Consolidated Statements of Income. Further, the assets and liabilities of Conectiv Energy, excluding the related current and deferred income tax accounts and certain retained liabilities, are reported as held for sale as of each date presented in the accompanying Consolidated Balance Sheets.

The remaining net assets of Conectiv Energy are $2 million at September 30, 2011 and primarily include miscellaneous investments. Net assets at December 31, 2010 of $45 million included accounts receivable of $81 million, inventory of $20 million, net derivative liabilities of $18 million and other miscellaneous receivables and payables. At September 30, 2011, there were no derivative assets and liabilities or financial assets and liabilities that would be accounted for at fair value on a recurring basis. At December 31, 2010, Conectiv Energy had $7 million of financial assets (with $4 million and $3 million categorized within levels 2 and 3 of the fair value hierarchy, respectively) and $90 million of financial liabilities accounted for at fair value on a recurring basis (with $10 million and $80 million categorized within levels 1 and 2 of the fair value hierarchy, respectively).

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Operating Results

The operating results of Conectiv Energy are as follows:

	Three Months  Ended September 30,					Nine Months  Ended September 30,
	2011		2010			2011		2010
	(millions of dollars)
(Loss) income from operations of discontinued operations, net of income taxes	$	—	$	(6	)	$	1	$	2
Net gains (losses) from dispositions of assets and businesses of discontinued operations, net of income taxes		—		2			—		(128	)
(Loss) income from discontinued operations, net of income taxes	$	—	$	(4	)	$	1	$	(126	)

(Loss) income from operations of discontinued operations, net of income taxes, for the nine months ended September 30, 2011, includes adjustments of $4 million to certain remaining miscellaneous assets and liabilities. In addition, adjustments were made to certain accrued expenses for obligations associated with the sale of the wholesale power generation business to Calpine to reflect the actual amounts paid to Calpine during the nine months ended September 30, 2011. For the three and nine months ended September 30, 2010, (loss) income from operations of discontinued operations, net of income taxes, includes after-tax expenses for employee severance and retention benefits of $9 million and after-tax accrued expenses for certain obligations associated with the sale of the wholesale power generation business to Calpine of $12 million.

Net gains (losses) from dispositions of assets and businesses of discontinued operations, net of income taxes for the nine months ended September 30, 2011 includes after-tax income of $1 million related to the sale of a tolling agreement in May 2011, which is offset by an expense of approximately $1 million (after-tax) which was incurred in connection with a financial transaction entered into with a third party on January 6, 2011, under which Conectiv Energy transferred to the third party its remaining portfolio of derivatives, including financially settled natural gas and electric power transactions, for all remaining periods from February 1, 2011 forward. In connection with the closing of the transaction, Conectiv paid the third party $82 million, primarily representing the fair value of the derivatives at February 1, 2011, and an after-tax administrative fee of $1 million. Substantially all of the mark-to-market gains and losses associated with these derivatives were recorded in earnings through December 31, 2010 and accordingly no additional material gain or loss was recognized as a result of this transaction in 2011.

Net gains (losses) from dispositions of assets and businesses of discontinued operations, net of income taxes, for the three and nine months ended September 30, 2010, includes (i) the after-tax loss on the sale of the wholesale power generation business to Calpine of $73 million (which is inclusive of the after-tax writedown of $67 million recorded in the second quarter of 2010 and was subject to final post-closing adjustments), (ii) after-tax net losses on sales of assets and businesses not sold to Calpine of $27 million (inclusive of the recognition of after-tax unrealized losses on derivative contracts considered no longer probable to occur of $50 million recorded in the second quarter of 2010), and (iii) tax charges aggregating $28 million for the establishment of valuation allowances against certain deferred tax assets primarily associated with state net operating losses, the remeasurement of deferred taxes for expected changes in state income tax apportionment factors, and the write-off of certain tax credit carryforwards no longer expected to be realized.

Derivative Instruments and Hedging Activities

Conectiv Energy historically used derivative instruments primarily to reduce its financial exposure to changes in the value of its assets and obligations due to commodity price fluctuations. The derivative instruments used included forward contracts, futures, swaps, and exchange-traded and over-the-counter options. The two primary risk management objectives were: (i) to manage the spread between the cost of fuel used to operate electric generation facilities and the revenue received from the sale of the power produced by those facilities,

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and (ii) to manage the spread between wholesale sale commitments and the cost of supply used to service those commitments to ensure stable cash flows and lock in favorable prices and margins when they became available.

As of September 30, 2011, Conectiv Energy had disposed of all energy commodity contracts and all cash collateral associated with these contracts had been returned.

Through June 30, 2010, Conectiv Energy purchased energy commodity contracts in the form of futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas, oil and coal to fuel its generation assets for sale to customers. Conectiv Energy also purchased energy commodity contracts in the form of electricity swaps, options and forward contracts to hedge price risk in connection with the purchase of electricity for distribution to requirements-load customers. Conectiv Energy accounted for most of its futures, swaps and certain forward contracts as cash flow hedges of forecasted transactions, and accordingly, the effective portion of the gains or losses on these derivatives were reflected as a component of AOCL and were reclassified into income in the same period or periods during which the hedged transactions occurred. Gains and losses on the derivatives representing hedge ineffectiveness, the forecasted hedged transaction being probable not to occur, or hedge components excluded from the assessment of effectiveness were recognized in current income.

The amounts of pre-tax loss on commodity derivatives included in other comprehensive loss for Conectiv Energy for the three and nine months ended September 30, 2011 and 2010 is provided in the table below:

	Three Months  Ended September 30,					Nine Months  Ended September 30,
	2011		2010			2011		2010
	(millions of dollars)
Amount of net pre-tax gain (loss) arising during the period included in accumulated other comprehensive loss	$	—	$	(5	)	$	—	$	(79	)
Amount of net pre-tax loss reclassified into income:
Effective portion:
Loss from discontinued operations, net of income taxes		—		28			—		134
Ineffective portion:
(Gain) losses from discontinued operations, net of income taxes (a)		—		(2	)		—		85
Total net pre-tax loss reclassified into income		—		26			—		219
Net pre-tax gain on commodity derivatives included in accumulated other comprehensive loss comprehensive loss	$	—	$	21		$	—	$	140

(a) For the three and nine months ended September 30, 2010, amounts of $(2) million and $86 million, respectively, were reclassified from AOCL to income because the forecasted transactions were deemed probable not to occur.

To the extent that Conectiv Energy held certain derivatives that did not qualify as hedges, these derivatives were recorded at fair value on the balance sheet with changes in fair value recognized in income. The amounts of realized and unrealized derivative gains (losses) for Conectiv Energy included in (Loss) income from discontinued operations, net of income taxes, for the three and nine months ended September 30, 2011 and 2010, is provided in the table below:

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	Three Months  Ended September 30,					Nine Months  Ended September 30,
	2011		2010			2011		2010
	(millions of dollars)
Realized mark-to-market gains	$	—	$	3		$	—	$	29
Unrealized mark-to-market losses		—		(3	)		—		(27	)
Total net mark-to-market gains (losses)	$	—	$	—		$	—	$	2

(17)RESTRUCTURING CHARGE

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy, PHI repositioned itself as a regulated transmission and distribution company during 2010. In connection with this repositioning, PHI completed a comprehensive organizational review in 2010 that identified opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments, which resulted in the adoption of a restructuring plan. PHI began implementation of the plan during 2010, identifying 164 employee positions that were eliminated. The plan also includes additional cost reduction opportunities that are being implemented through process improvements and operational efficiencies.

In connection with the restructuring plan, PHI recorded a pre-tax restructuring charge related to severance, pension, and health and welfare benefits for employee terminations of $30 million in 2010, of which $14 million was recorded in the three and nine months ended September 30, 2010. The severance, pension, and health and welfare benefits were estimated based on the years of service and compensation levels of the employees associated with the 164 eliminated positions. The restructuring charge was allocated to PHI’s operating segments and was reflected as a separate line item in the Consolidated Statement of Income for the year ended December 31, 2010.

A reconciliation of PHI’s accrued restructuring charges for the three and nine months ended September 30, 2011 is as follows:

	Three Months Ended September 30, 2011
	(millions of dollars)
	Power Delivery			Corporate and Other		PHI Consolidated
Beginning balance as of July 1, 2011	$	6		$	—	$	6
Restructuring charge		—			—		—
Cash payments		(1	)		—		(1	)
Ending balance as of September 30, 2011	$	5		$	—	$	5

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	Nine Months Ended September 30, 2011
	(millions of dollars)
	Power Delivery			Corporate and Other			PHI Consolidated
Beginning balance as of January 1, 2011	$	28		$	1		$	29
Restructuring charge		—			—			—
Cash payments		(23	)		(1	)		(24	)
Ending balance as of September 30, 2011	$	5		$	—		$	5

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(millions of dollars)
Operating Revenue	$	603		$	706		$	1,643		$	1,797
Operating Expenses
Purchased energy		258			356			731			932
Other operation and maintenance		111			93			313			252
Restructuring charge		—			6			—			6
Depreciation and amortization		44			43			128			121
Other taxes		108			110			294			273
Effects of divestiture-related claims		—			9			—			11
Total Operating Expenses		521			617			1,466			1,595
Operating Income		82			89			177			202
Other Income (Expenses)
Interest and dividend income		—			—			—			1
Interest expense		(24	)		(24	)		(70	)		(74	)
Other income		3			5			13			10
Total Other Expenses		(21	)		(19	)		(57	)		(63	)
Income Before Income Tax Expense		61			70			120			139
Income Tax Expense		23			33			32			62
Net Income		38			37			88			77
Retained Earnings at Beginning of Period		773			720			723			730
Dividends paid to Parent		—			(45	)		—			(95	)
Retained Earnings at End of Period	$	811		$	712		$	811		$	712

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	September 30, 2011			December 31, 2010
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	70		$	88
Accounts receivable, less allowance for uncollectible accounts of $22 million and $20 million, respectively		375			373
Inventories		54			44
Prepayments of income taxes		30			95
Income taxes receivable		31			37
Prepaid expenses and other		38			34
Total Current Assets		598			671
INVESTMENTS AND OTHER ASSETS
Regulatory assets		259			191
Prepaid pension expense		296			274
Investment in trust		31			25
Income taxes receivable		24			34
Other		55			57
Total Investments and Other Assets		665			581
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		6,475			6,185
Accumulated depreciation		(2,697	)		(2,609	)
Net Property, Plant and Equipment		3,778			3,576
TOTAL ASSETS	$	5,041		$	4,828

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	September 30, 2011		December 31, 2010
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	196	$	194
Accounts payable due to associated companies		69		75
Capital lease obligations due within one year		8		8
Taxes accrued		73		62
Interest accrued		36		18
Other		108		119
Total Current Liabilities		490		476
DEFERRED CREDITS
Regulatory liabilities		169		147
Deferred income taxes, net		1,033		958
Investment tax credits		5		7
Other postretirement benefit obligations		70		67
Income taxes payable		—		3
Liabilities and accrued interest related to uncertain tax positions		71		52
Other		65		64
Total Deferred Credits		1,413		1,298
LONG-TERM LIABILITIES
Long-term debt		1,540		1,540
Capital lease obligations		82		86
Total Long-Term Liabilities		1,622		1,626
COMMITMENTS AND CONTINGENCIES (NOTE 10)
EQUITY
Common stock, $.01 par value, 200,000,000 shares authorized, 100 shares outstanding		—		—
Premium on stock and other capital contributions		705		705
Retained earnings		811		723
Total Equity		1,516		1,428
TOTAL LIABILITIES AND EQUITY	$	5,041	$	4,828

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

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months  Ended September 30,
	2011			2010
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	88		$	77
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		128			121
Effects of divestiture-related claims		—			11
Deferred income taxes		58			50
Changes in:
Accounts receivable		5			(40	)
Regulatory assets and liabilities, net		(16	)		(25	)
Accounts payable and accrued liabilities		(21	)		12
Pension contributions		(40	)		—
Taxes accrued		92			60
Other assets and liabilities		36			27
Net Cash From Operating Activities		330			293
INVESTING ACTIVITIES
Investment in property, plant and equipment		(361	)		(225	)
Department of Energy capital reimbursement awards received		24			3
Net other investing activities		(8	)		—
Net Cash Used By Investing Activities		(345	)		(222	)
FINANCING ACTIVITIES
Dividends paid to Parent		—			(95	)
Reacquisition of long-term debt		—			(16	)
Net other financing activities		(3	)		4
Net Cash Used by Financing Activities		(3	)		(107	)
Net Decrease in Cash and Cash Equivalents		(18	)		(36	)
Cash and Cash Equivalents at Beginning of Period		88			213
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	70		$	177
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes (includes payments from PHI for federal income taxes)	$	108		$	25

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 the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive energy supplier. 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, 2010. In the opinion of Pepco’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to state fairly Pepco’s financial condition as of September 30, 2011, in accordance with GAAP. The year-end December 31, 2010 Balance Sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and nine months ended September 30, 2011 may not be indicative of results that will be realized for the full year ending December 31, 2011 since the sales of electric energy are seasonal.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although Pepco believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of restructuring charges, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto liability claims and income tax provisions and reserves. Additionally, Pepco is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. Pepco records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Storm Costs

During the third quarter of 2011, Pepco incurred significant costs associated with Hurricane Irene that affected its service territory. Total incremental storm costs associated with Hurricane Irene were $22 million, with $14 million incurred for repair work and $8 million incurred as capital expenditures. Costs incurred for repair work of $12 million were deferred as a regulatory asset to reflect the probable recovery of these storm costs in Pepco’s jurisdictions, and the remaining $2 million was charged to Other operation and maintenance expense. Approximately $16 million of these total incremental storm costs have been estimated

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for the cost of restoration services provided by outside contractors since a large portion of the invoices for such services had not been received at September 30, 2011. Actual invoices may vary from these estimates. Pepco currently plans to seek recovery of the incremental Hurricane Irene costs in each of its jurisdictions in pending or planned distribution rate case filings.

Network Service Transmission Rates

In May 2011, Pepco filed its network service transmission rates with the Federal Energy Regulatory Commission effective for the service year beginning June 1, 2011. The new rates include an adjustment for costs incurred in the service year ended May 31, 2011 that were not reflected in the rates charged to customers for that service year. In the second quarter of 2011, Pepco recorded a $2 million decrease in transmission revenues as a change to the estimates recorded in previous periods primarily due to a decrease in the actual rate base versus the estimated rate base.

For the nine months ended September 30, 2010, Pepco recorded a $3 million increase in transmission service revenue associated with a change to the estimates recorded in previous periods.

General and Auto Liability

During the second quarter of 2011, Pepco reduced its self-insurance reserves for general and auto liability claims by approximately $1 million, based on obtaining an actuarial estimate of the unpaid loss attributable to general and auto liability claims for Pepco at June 30, 2011.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $100 million and $106 million for the three months ended September 30, 2011 and 2010, respectively, and $271 million and $249 million for the nine months ended September 30, 2011 and 2010, respectively.

Reclassifications and Adjustments

Certain prior period amounts have been reclassified in order to conform to the current period presentation. The following adjustments have been recorded which are not considered material individually or in the aggregate:

Income Tax Adjustments

During the first quarter of 2011, Pepco recorded an adjustment to correct certain income tax errors related to prior periods associated with the interest on uncertain tax positions. The adjustment resulted in an increase in income tax expense of $1 million for the nine months ended September 30, 2011.

In the third quarter of 2010, Pepco recorded certain adjustments to correct errors in Income tax expense which resulted in an increase to Income tax expense of $4 million for the three and nine months ended September 30, 2010.

Other Taxes Adjustment

In the third quarter of 2010, Pepco recorded an adjustment to correct certain errors related to other taxes which resulted in a decrease to Other taxes expense of $5 million (pre-tax) for the three and nine months ended September 30, 2010.

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(3)NEWLY ADOPTED ACCOUNTING STANDARDS

Fair Value Measurements and Disclosures (Accounting Standards Codification (ASC) 820)

The Financial Accounting Standards Board (FASB) issued new disclosure requirements that require significant items within the reconciliation of the Level 3 valuation category to be presented in separate categories for purchases, sales, issuances and settlements. The guidance was effective beginning with Pepco’s March 31, 2011 financial statements. Pepco has included the new disclosure requirements in Note (9), “Fair Value Disclosures,” to its financial statements.

(4)RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements and Disclosures (ASC 820)

In May 2011, the FASB issued new guidance on fair value measurement and disclosures that will be effective beginning with Pepco’s March 31, 2012 financial statements. The new guidance will change how fair value is measured in specific instances and expand disclosures about fair value measurements. Pepco is evaluating the impact of this new guidance on its financial statements.

Compensation Retirement Benefits Multiemployer Plans (ASC 715-80)

In September 2011, the FASB issued new disclosure requirements for participants in multiemployer pension and postretirement benefit plans. The disclosures are intended to indicate the financial health of the plans and the potential future cash flow implications for participants in the plans. The new disclosures are effective beginning with Pepco’s December 31, 2011 financial statements and prior periods presented. Pepco is evaluating the impact of this new guidance on its financial statements.

(5) SEGMENT INFORMATION

The company operates its business as one regulated utility segment, which includes all of its services as described above.

(6) PENSION AND OTHER POSTRETIREMENT BENEFITS

Pepco accounts for its participation in its parent’s single-employer plans, the Pepco Holdings, Inc. Retirement Plan (the PHI Retirement Plan) and the Pepco Holdings, Inc. Welfare Plan for Retirees, as participation in multiemployer plans. PHI’s pension and other postretirement net periodic benefit cost for the three months ended September 30, 2011 and 2010, before intercompany allocations from the PHI Service Company, were $24 million and $26 million, respectively. Pepco’s allocated share was $15 million and $10 million, respectively, for the three months ended September 30, 2011 and 2010. PHI’s pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2011 and 2010, before intercompany allocations from the PHI Service Company, were $70 million and $86 million, respectively. Pepco’s allocated share was $32 million and $30 million, respectively, for the nine months ended September 30, 2011 and 2010.

On March 14, 2011, Pepco made a discretionary tax-deductible contribution to the non-contributory PHI Retirement Plan of $40 million. Pepco did not make a contribution to the PHI Retirement Plan in 2010.

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(7) DEBT

Credit Facility

On August 1, 2011, PHI, Pepco, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE) entered into an amendment and restatement of their $1.5 billion credit facility to extend the expiration date of the facility to August 1, 2016, and to make various other changes. As amended and restated, all or any portion of the facility may be used to obtain revolving loans and up to $500 million may be used to obtain letters of credit. PHI’s credit sublimit under the facility is $750 million and the sublimit of each of Pepco, DPL and ACE is $250 million. The borrowers may increase or decrease their respective sublimits during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of sublimit reallocations cannot exceed eight per fiscal year during the term of the agreement.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and one month LIBOR plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. The facility also includes a “swingline loan sub-facility,” pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt thereof. All indebtedness incurred under the facility is unsecured.

At September 30, 2011 and December 31, 2010, the aggregate amount of cash plus unused borrowing capacity under the $1.5 billion credit facility available to meet the future liquidity needs of PHI’s utility subsidiaries was $831 million and $462 million, respectively.

(8) INCOME TAXES

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

	Three Months Ended September 30,											Nine Months Ended September 30,
	2011					2010						2011					2010
	(millions of dollars)
Income tax at federal statutory rate	$	21		35.0	%		$	25		35.0	%	$	42		35.0	%		$	49		35.0	%
Increases (decreases) resulting from:
Depreciation		—		—				1		1.7			—		—				4		2.7
Change in estimates and interest related to uncertain and effectively settled tax positions		1		1.3				5		6.8			(4	)	(2.7	)			7		5.1
State income taxes, net of federal effect		4		6.1				4		5.4			6		5.3				8		5.5
Permanent differences related to deferred compensation funding		—		(0.3	)			—		(0.4	)		(2	)	(1.4	)			(1	)	(0.6	)
State tax benefit related to prior years’ asset dispositions		—		—				—		—			(4	)	(3.5	)			—		—
Asset removal costs		(2	)	(3.0	)			(1	)	(1.0	)		(4	)	(3.7	)			(2	)	(1.3	)
Other, net		(1	)	(1.4	)			(1	)	(0.4	)		(2	)	(2.3	)			(3	)	(1.8	)
Income tax expense	$	23		37.7	%		$	33		47.1	%	$	32		26.7	%		$	62		44.6	%

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Three Months Ended September 30, 2011 and 2010

Pepco’s effective tax rates for the three months ended September 30, 2011 and 2010 were 37.7% and 47.1%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions and an increase in certain asset removal costs.

During the third quarter of 2011, Pepco recalculated interest on its uncertain tax positions for open tax years based on different assumptions related to the application of its deposit made with the Internal Revenue Service in 2006. This resulted in an additional tax expense of $1 million (after-tax). Further during the third quarter of 2010, Pepco reversed $2 million of previously recorded tax benefits related to changes in estimates and interests related to uncertain and effectively settle tax positions.

Nine Months Ended September 30, 2011 and 2010

Pepco’s effective tax rates for the nine months ended September 30, 2011 and 2010 were 26.7% and 44.6%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions, and a state tax benefit recorded in 2011 related to prior year’s asset dispositions.

During the second quarter of 2011, PHI reached a settlement with the Internal Revenue Service (IRS) with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, Pepco has recorded an additional tax benefit in the amount of $5 million (after-tax). This additional interest income was recorded in the second quarter of 2011. This was partially offset by the recalculation of interest on Pepco’s uncertain tax positions for open tax years discussed above.

In May 2011, Pepco received refunds of approximately $5 million and recorded tax benefits of approximately $4 million (after-tax) related to the filing of amended state tax returns. These amended returns reduced state taxable income as a result of an increase in tax basis on certain prior years’ asset dispositions.

(9) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

Pepco applies FASB guidance on fair value measurement and disclosures (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, 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. The guidance 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) and the lowest priority to unobservable inputs (level 3). Pepco classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation 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 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 and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Executive deferred compensation plan assets consist of life insurance policies that are categorized as level 2 assets because they are priced based on the assets underlying the policies, which consist of short-term cash equivalents and fixed income securities that are priced using observable market data. The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.

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.

Executive deferred compensation plan assets and liabilities that are classified as level 3 include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies, which does not represent a quoted price in an active market.

The following tables set forth, by level within the fair value hierarchy, Pepco’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2011 and December 31, 2010. As required by the guidance, 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 the exercise of 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 September 30, 2011
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Executive deferred compensation plan assets
Money Market Funds	$	15	$	15	$	—	$	—
Life Insurance Contracts		54		—		38		16
	$	69	$	15	$	38	$	16
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	10	$	—	$	10	$	—
	$	10	$	—	$	10	$	—

(a) There were no significant transfers of instruments between level 1 and level 2 valuation categories.

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	Fair Value Measurements at December 31, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Executive deferred compensation plan assets
Money Market Funds	$	6	$	6	$	—	$	—
Life Insurance Contracts		59		—		41		18
	$	65	$	6	$	41	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	11	$	—	$	11	$	—
	$	11	$	—	$	11	$	—

(a) There were no significant transfers of instruments between level 1 and level 2 valuation categories.

Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (level 3) for the nine months ended September 30, 2011 and 2010 are shown below:

	Life Insurance Contracts
	Nine Months Ended September 30,
	2011			2010
	(millions of dollars)
Beginning balance as of January 1	$	18		$	18
Total gains or (losses) (realized and unrealized)
Included in income		5			3
Included in accumulated other comprehensive loss		—			—
Purchases		—			—
Issuances		(3	)		(3	)
Settlements		(4	)		—
Transfers in (out) of level 3		—			—
Ending balance as of June 30	$	16		$	18

The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of “Other income” or “Other operation and maintenance” expense for the periods below were as follows:

	Nine Months  Ended September 30,
	2011		2010
	(millions of dollars)
Total gains included in income for the period	$	5	$	3
Change in unrealized gains relating to assets still held at reporting date	$	2	$	3

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Other Financial Instruments

The estimated fair values of Pepco’s issued debt instruments at September 30, 2011 and December 31, 2010 are shown below:

	September 30, 2011				December 31, 2010
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	1,540	$	1,915	$	1,540	$	1,722

The fair value of long-term debt issued by Pepco was based on actual trade prices as of September 30, 2011 and December 31, 2010. Where trade prices were not available, Pepco used other valuation methodologies deemed appropriate by management to estimate fair value.

The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.

(10)COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

District of Columbia Divestiture Case

In June 2000, the District of Columbia Public Service Commission (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 in 2000. This approval left unresolved issues of (i) 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 and (ii) whether Pepco was entitled to deduct certain costs in determining the amount of proceeds to be shared.

In May 2010, the DCPSC issued an order addressing all of the remaining issues related to the sharing of the proceeds of Pepco’s divestiture of its generating assets. In the order, the DCPSC ruled that Pepco is not required to share EDIT and ADITC with customers. However, the order also disallowed certain items that Pepco had included in the costs deducted from the proceeds of the sale of the generation assets. The disallowance of these costs, together with interest on the disallowed amount, increased the aggregate amount Pepco was required to distribute to customers, pursuant to the sharing formula, by approximately $11 million, which Pepco recognized as an expense in 2010 and refunded the amounts to its customers. In June 2010, Pepco filed an application for reconsideration of the DCPSC’s order. In July 2010, the DCPSC denied Pepco’s application for reconsideration. In September 2010, Pepco filed an appeal of the DCPSC’s decision with the District of Columbia Court of Appeals. On April 12, 2011, the Court of Appeals affirmed the DCPSC order. Pepco does not intend to appeal this decision.

Maryland Public Service Commission Reliability Investigation

In August 2010, following major storm events that occurred in July and August 2010, the Maryland Public Service Commission (MPSC) initiated a proceeding for the purpose of investigating the reliability of the Pepco distribution system and the quality of distribution service Pepco is providing its customers. On February 10, 2011, the MPSC issued a notice identifying as possible remedies the imposition of civil

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penalties, changes in the manner of Pepco’s operations, modification of Pepco’s service territory and revocation of Pepco’s authority to exercise its public utility franchise. Pepco’s position in this proceeding is that while it is implementing a comprehensive program that will improve the reliability of its distribution system and its planning for, and response to, adverse weather events, there is no evidentiary support to impose sanctions for past performance. The other parties, including the staff of the MPSC, the Maryland Office of People’s Counsel, the Maryland Energy Administration, and Montgomery County, Maryland, contend that Pepco’s service reliability has not met an acceptable level and have recommended a variety of sanctions, including, but not limited to, the imposition of significant fines, the denial of rate recovery for reliability improvement costs, a reduction in Pepco’s return on equity (ROE), restrictions on dividends to PHI in order to fund reliability improvement costs, compliance with enhanced reliability requirements within a specified period and various reporting requirements. While Pepco is committed to improving the reliability of its electric service, it is vigorously opposing the imposition of the sanctions requested by the other parties, which Pepco believes are unsupported by the record in this case. Pepco is unable to predict the outcome of this proceeding at this time.

Rate Proceedings

Over the last several years, Pepco has proposed in each of its service territories the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date, a bill stabilization adjustment (BSA) has been approved and implemented for electric service in Maryland and in the District of Columbia. The MPSC has initiated a proceeding to review how the BSA operates in Maryland to recover revenues lost as a result of major storm outages (as discussed below). Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission.

On February 1, 2011, the MPSC initiated proceedings involving Pepco, as well as DPL and unaffiliated utilities including Baltimore Gas & Electric Company and Southern Maryland Electric Cooperative, for the purpose of reviewing how the BSA operates to recover revenues lost as a result of major storm outages. In its orders initiating the proceedings, the MPSC expressed concern that the utilities’ respective BSAs may be allowing them to recover revenues lost during extended outages, therefore unintentionally eliminating an incentive to restore service quickly. The MPSC will consider whether the BSA, as currently in effect, is appropriate, whether the calculations or determinant factors for calculating the BSA should be modified, and if so, what modifications should be made. On July 22, 2011, the MPSC held a legislative-style hearing on this matter. A provision that excludes revenues lost as a result of major storm outages from the calculation of future BSA adjustments is already included in the BSA for Pepco in the District of Columbia as approved by the DCPSC. If the MPSC were to implement a change similar to the provision in effect in the District of Columbia, the financial impact of service interruptions due to a major storm would generally depend on the scope and duration of the outages. The potential financial impact of any modification to the BSA cannot be assessed until the details of the modification are known.

District of Columbia

On July 8, 2011, Pepco filed an application with the DCPSC to increase its electric distribution base rates by approximately $42 million annually, based on an ROE of 10.75%. A decision by the DCPSC is expected in the second quarter of 2012.

General Litigation

In 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

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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.

As of September 30, 2011, there are approximately 180 cases still pending against Pepco in the Maryland State Courts, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant Corporation (Mirant) for defense and indemnification in connection with the sale by Pepco of 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. If an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepco’s and PHI’s financial condition, results of operations and 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. Although penalties assessed for violations of environmental laws and regulations are not recoverable from Pepco’s customers, environmental clean-up costs incurred by Pepco would be included in its cost of service for ratemaking purposes.

Peck Iron and Metal Site. The U.S. Environmental Protection Agency (EPA) informed Pepco in a May 2009 letter that Pepco may be a potentially responsible party (PRP) under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that Peck’s metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by former Peck Iron and Metal personnel, who informed EPA that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales may be entitled to the recyclable material exemption from CERCLA liability. In a Federal Register notice published on November 4, 2009, EPA placed the Peck Iron and Metal site on the National Priorities List (NPL). The NPL, among other things, serves as a guide to EPA in determining which sites warrant further investigation to assess the nature and extent of the human health and environmental risks associated with a site. In a July 12, 2011 letter, EPA invited Pepco to enter into discussions with the agency to conduct a remedial investigation/feasibility study (RI/FS) at the site. Pepco is evaluating EPA’s invitation, but cannot at this time predict the costs of the RI/FS, the cost of performing a remedy at the site or the amount of such costs that EPA might seek to impose on Pepco.

Ward Transformer Site. In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including Pepco with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. With input from the court, the parties are discussing the next step in the litigation, which is likely to be the filing of summary judgment motions regarding liability for certain “test case” defendants other than Pepco. The case is expected to be stayed as to the remaining defendants pending rulings upon the test cases. Although the magnitude of the potential liability at this site is

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not known at this time, Pepco does not believe that it had extensive business transactions, if any, with the Ward Transformer site and therefore, costs incurred to resolve this matter are not expected to be material.

Benning Road Site. In September 2010, PHI received a letter from EPA stating that EPA and the District of Columbia Department of the Environment (DDOE) have identified the Benning Road location, consisting of a transmission and distribution facility operated by Pepco and a generation facility operated by Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The letter stated that the principal contaminants of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons, that EPA is monitoring the efforts of DDOE and that EPA intends to use federal authority to address the Benning Road site if an agreement for a comprehensive study to evaluate (and, if necessary, to clean up) the facility is not reached.

In January 2011, Pepco and Pepco Energy Services entered into a proposed consent decree with DDOE that requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10-15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for DDOE’s selection of a remedial action for the Benning Road site and for the Anacostia River sediment associated with the site. In February 2011, the District filed a complaint against Pepco and Pepco Energy Services in the United States District Court for the District of Columbia for the purpose of obtaining judicial approval of the consent decree. The complaint asserted claims under CERCLA, the Resource Conservation and Recovery Act, and District of Columbia law seeking to compel Pepco and Pepco Energy Services to take actions to investigate and clean up contamination allegedly originating from the Benning Road site, and to reimburse the District for its response costs. The filing of this complaint was not intended to lead to active litigation. Rather, after receiving public comment on the proposed consent decree, DDOE planned to file a motion requesting the District Court to enter the consent decree. In March 2011, Anacostia Riverkeeper, Inc., the Anacostia Watershed Society and the Natural Resources Defense Council (collectively, the Environmental Organizations) submitted comments to DDOE objecting to the proposed consent decree on several grounds. In April 2011, while DDOE was preparing its response to comments received on the proposed consent decree, the Environmental Organizations filed a motion to intervene as plaintiffs in the District Court action. Pepco and Pepco Energy Services and DDOE have filed briefs opposing their intervention motion. In August, DDOE, Pepco and Pepco Energy Services agreed to certain revisions to the consent decree to address some of the comments from the Environmental Organizations. On September 1, 2011, DDOE filed a motion asking the District Court to enter the revised consent decree (and at the same time deny the Environmental Organizations’ motion to intervene). Briefing is complete on the motion to intervene and the motion to enter the consent decree. These motions are ready for decision by the District Court, but no decision has yet been issued. If the District Court allows the Environmental Organizations to intervene and become parties to the litigation, the settlement of the litigation by means of the consent decree will require their agreement, which could require changes to the terms of the consent decree – including the nature and scope of the work required to be performed by Pepco and Pepco Energy Services. Work on the RI/FS is not expected to begin until this matter is resolved.

At the present time, in light of the efforts by DDOE, Pepco and Pepco Energy Services to address the site through the proposed consent decree, Pepco and Pepco Energy Services anticipate that EPA will continue to refrain from listing the Benning Road facility on the NPL. The current estimate of the costs for performing the RI/FS is approximately $1 million. The remediation costs cannot be determined until the RI/FS is completed and the nature and scope of any remedial action are defined. However, the remediation costs are preliminarily projected to be approximately $13 million. As of September 30, 2011, PHI had an accrued liability of approximately $14 million with respect to this matter.

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Potomac River Mineral Oil Release. On January 23, 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at Pepco’s Potomac River substation in Alexandria, Virginia. An overflow of an underground secondary containment reservoir resulted in approximately 4,500 gallons of mineral oil flowing into the Potomac River.

The release falls within the regulatory jurisdiction of multiple federal and state agencies. Beginning in March 2011, DDOE issued a series of compliance directives that require Pepco to prepare an incident report, provide certain records, and prepare and implement plans for sampling surface water and river sediments and assessing ecological risks and natural resources damages. Pepco has submitted the requested incident report and provided the requested records and on October 21, 2011, received DDOE approval of Pepco’s work plans for the sampling and assessment work.

On March 16, 2011, the Virginia Department of Environmental Quality (VADEQ) requested documentation regarding the release and the preparation of an emergency response report, which Pepco submitted to the agency on April 20, 2011. On March 25, 2011, Pepco received a notice of violation from VADEQ and in August 2011, Pepco executed a consent agreement with VADEQ pursuant to which Pepco will be obligated to pay a civil penalty of approximately $40,000. The consent agreement states that VADEQ has determined that no further action is necessary to remediate the mineral oil spill at the facility (although DDOE retains jurisdiction to require further response actions to assess possible impacts to the river). The Virginia State Water Control Board is expected to approve the consent agreement at its December 2011 meeting, after which it will be executed by VADEQ.

During March 2011, EPA conducted an inspection of the Potomac River substation to review compliance with federal regulations regarding Spill Prevention, Control, and Countermeasure (SPCC) plans for facilities using oil-containing equipment in proximity to surface waters. Following the inspection, EPA advised Pepco that it had identified several potential violations of the SPCC regulations relating to SPCC plan content, recordkeeping, and secondary containment, which may lead to an EPA demand for noncompliance penalties. As a result of the oil release, Pepco submitted a revised SPCC plan to EPA on August 18, 2011. Pepco also implemented certain changes to the existing containment systems at the facility on an interim basis in accordance with the revisions to the SPCC plan, and is evaluating certain permanent changes to the containment systems. During the third quarter of 2011, a study performed by PHI estimated the remediation costs at, and PHI accrued, approximately $1 million.

The U.S. Coast Guard has assessed a $5,000 penalty against Pepco for the release of oil into the waters of the United States, which Pepco has paid.

The amount of penalties, if any, that may be imposed by DDOE and/or EPA and the costs associated with possible additional changes to the containment system, possible additional response actions, or possible natural resource damage claims cannot be estimated at this time; however, based on current information, PHI and Pepco do not believe this matter will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

District of Columbia Tax Legislation

On June 14, 2011, the Council of the District of Columbia approved the Fiscal Year 2012 Budget Support Act of 2011 (Budget Support Act). The Budget Support Act includes a provision requiring that corporate taxpayers in the District of Columbia (the District) calculate taxable income allocable or apportioned to the District by reference to the income and apportionment factors applicable to commonly controlled organizations organized within the United States that are engaged in a unitary business. This new reporting method was enacted on September 14, 2011 and is effective for tax years beginning on or after December 31, 2010. This new tax reporting method is reflected in Pepco’s results of operations, as further discussed in Note (8), “Income Taxes.”

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(11) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including Pepco. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to Pepco for the three months ended September 30, 2011 and 2010 were approximately $47 million and $51 million, respectively. PHI Service Company costs directly charged or allocated to Pepco for the nine months ended September 30, 2011 and 2010 were approximately $133 million and $137 million, respectively.

Certain subsidiaries of Pepco Energy Services, Inc. (collectively with its subsidiaries, Pepco Energy Services) perform utility maintenance services, including services that are treated as capital costs, for Pepco. Amounts charged to Pepco by these companies for the three months ended September 30, 2011 and 2010 were approximately $6 million and $3 million, respectively. Amounts charged to Pepco by these companies for the nine months ended September 30, 2011 and 2010 were approximately $14 million and $6 million, respectively.

As of September 30, 2011 and December 31, 2010, Pepco had the following balances on its Balance Sheets due to related parties:

	September 30, 2011			December 31, 2010
Asset (Liability)	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(23	)	$	(27	)
Pepco Energy Services (b)		(46	)		(48	)
Total	$	(69	)	$	(75	)
Money Pool Balance with Pepco Holdings (included in Cash and cash equivalents)	$	62		$	82

(a) These amounts are included in Accounts payable due to associated companies on the Balance Sheet.

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

(12)RESTRUCTURING CHARGE

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy Holding Company, PHI repositioned itself as a regulated transmission and distribution company during 2010. In connection with this repositioning, PHI completed a comprehensive organizational review in 2010 that identified opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments, which resulted in the adoption of a restructuring plan. PHI began implementation of the plan during 2010, identifying 164 employee positions that were eliminated. The plan also includes additional cost reduction opportunities that are being implemented through process improvements and operational efficiencies.

In connection with the restructuring plan, Pepco recorded a pre-tax restructuring charge related to its allocation of severance, pension, and health and welfare benefits for the termination of corporate services employees at PHI of $15 million in 2010, of which $6 million was recorded in the three and nine months ended September 30, 2010. The severance, pension, and health and welfare benefits were estimated based on the years of service and compensation levels of the employees associated with the 164 eliminated positions at PHI. The restructuring charge was reflected as a separate line item in the Statement of Income for the year ended December 31, 2010.

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A reconciliation of Pepco’s accrued restructuring charges for the three and nine months ended September 30, 2011 is as follows:

	Three Months  Ended September 30, 2011
	(millions of dollars)
Beginning balance as of July 1, 2011	$	3
Restructuring charge		—
Cash payments		—
Ending balance as of September 30, 2011	$	3

	Nine Months Ended September 30, 2011
	(millions of dollars)
Beginning balance as of January 1, 2011	$	15
Restructuring charge		—
Cash payments		(12	)
Ending balance as of September 30, 2011	$	3

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(millions of dollars)
Operating Revenue
Electric	$	298		$	342		$	841		$	901
Natural Gas		28			35			169			166
Total Operating Revenue		326			377			1,010			1,067
Operating Expenses
Purchased energy		180			225			507			585
Gas purchased		18			26			114			117
Other operation and maintenance		69			65			181			191
Restructuring charge		—			4			—			4
Depreciation and amortization		22			22			66			62
Other taxes		8			10			28			28
Total Operating Expenses		297			352			896			987
Operating Income		29			25			114			80
Other Income (Expenses)
Interest expense		(11	)		(10	)		(33	)		(32	)
Other income		3			1			7			4
Total Other Expenses		(8	)		(9	)		(26	)		(28	)
Income Before Income Tax Expense		21			16			88			52
Income Tax Expense		10			7			32			23
Net Income		11			9			56			29
Retained Earnings at Beginning of Period		539			469			494			472
Dividends paid to Parent		(50	)		—			(50	)		(23	)
Retained Earnings at End of Period	$	500		$	478		$	500		$	478

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	September 30, 2011			December 31, 2010
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	12		$	69
Accounts receivable, less allowance for uncollectible accounts of $13 million and $13 million, respectively		172			212
Inventories		46			41
Prepayments of income taxes		53			62
Prepaid expenses and other		31			22
Total Current Assets		314			406
INVESTMENTS AND OTHER ASSETS
Goodwill		8			8
Regulatory assets		232			242
Prepaid pension expense		166			139
Other		23			21
Total Investments and Other Assets		429			410
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		3,119			3,000
Accumulated depreciation		(925	)		(901	)
Net Property, Plant and Equipment		2,194			2,099
TOTAL ASSETS	$	2,937		$	2,915

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

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DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	September 30, 2011		December 31, 2010
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	105	$	105
Current portion of long-term debt		66		35
Accounts payable and accrued liabilities		92		98
Accounts payable due to associated companies		20		34
Taxes accrued		7		6
Interest accrued		12		7
Derivative liabilities		13		15
Other		55		73
Total Current Liabilities		370		373
DEFERRED CREDITS
Regulatory liabilities		294		310
Deferred income taxes, net		641		561
Investment tax credits		6		7
Other postretirement benefit obligations		25		22
Liabilities and accrued interest related to uncertain tax positions		14		24
Derivative liabilities		5		8
Other		36		39
Total Deferred Credits		1,021		971
LONG-TERM LIABILITIES
Long-term debt		699		730
COMMITMENTS AND CONTINGENCIES (NOTE 12)
EQUITY
Common stock, $2.25 par value, 1,000 shares authorized, 1,000 shares outstanding		—		—
Premium on stock and other capital contributions		347		347
Retained earnings		500		494
Total Equity		847		841
TOTAL LIABILITIES AND EQUITY	$	2,937	$	2,915

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

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2011			2010
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	56		$	29
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		66			62
Deferred income taxes		81			53
Changes in:
Accounts receivable		39			3
Inventories		(6	)		(2	)
Regulatory assets and liabilities, net		(34	)		(8	)
Accounts payable and accrued liabilities		(31	)		(3	)
Pension contributions		(40	)		—
Taxes accrued		(23	)		(22	)
Other assets and liabilities		22			33
Net Cash From Operating Activities		130			145
INVESTING ACTIVITIES
Investment in property, plant and equipment		(146	)		(191	)
Net other investing activities		—			3
Net Cash Used By Investing Activities		(146	)		(188	)
FINANCING ACTIVITIES
Dividends paid to Parent		(50	)		(23	)
Issuances of long-term debt		35			78
Reacquisition of long-term debt		(35	)		(31	)
Issuances of short-term debt, net		—			3
Net other financing activities		9			(5	)
Net Cash (Used by) From Financing Activities		(41	)		22
Net Decrease in Cash and Cash Equivalents		(57	)		(21	)
Cash and Cash Equivalents at Beginning of Period		69			26
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	12		$	5
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes (includes payments from PHI for federal income taxes)	$	24		$	5

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 provides natural gas distribution service in northern Delaware. Additionally, DPL provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive energy supplier. Default Electricity Supply is known as Standard Offer Service in both Delaware and Maryland. DPL is a wholly owned subsidiary of Conectiv, LLC, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).

(2)SIGNIFICANT ACCOUNTING POLICIES

Financial Statement Presentation

DPL’s unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in DPL’s Annual Report on Form 10-K for the year ended December 31, 2010. In the opinion of DPL’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to state fairly DPL’s financial condition as of September 30, 2011, in accordance with GAAP. The year-end December 31, 2010 Balance Sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and nine months ended September 30, 2011 may not be indicative of results that will be realized for the full year ending December 31, 2011 since the sales of electric energy and natural gas are seasonal.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although DPL believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment evaluations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of restructuring charges, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto liability claims and income tax provisions and reserves. Additionally, DPL is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. DPL records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

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Storm Costs

During the third quarter of 2011, DPL incurred significant costs associated with Hurricane Irene that affected its service territory. Total incremental storm costs associated with Hurricane Irene were $12 million, with $9 million incurred for repair work and $3 million incurred as capital expenditures. Costs incurred for repair work of $5 million were deferred as a regulatory asset to reflect the probable recovery of these storm costs in DPL’s jurisdictions, and the remaining $4 million was charged to Other operation and maintenance expense. Approximately $7 million of these total incremental storm costs have been estimated for the cost of restoration services provided by outside contractors since a large portion of the invoices for such services had not been received at September 30, 2011. Actual invoices may vary from these estimates. DPL currently plans to seek recovery of the incremental Hurricane Irene costs in each of its jurisdictions in planned distribution rate case filings.

Network Service Transmission Rates

In May 2011, DPL filed its network service transmission rates with the Federal Energy Regulatory Commission effective for the service year beginning June 1, 2011. The new rates include an adjustment for costs incurred in the service year ended May 31, 2011 that were not reflected in the rates charged to customers for that service year. In the second quarter of 2011, DPL recorded a $2 million decrease in transmission revenues as a change to the estimates recorded in previous periods due to a decrease in the actual rate base versus the estimated rate base.

For the nine months ended September 30, 2010, DPL recorded a $3 million increase in transmission service revenue associated with a change to the estimates recorded in previous periods.

General and Auto Liability

During the second quarter of 2011, DPL reduced its self-insurance reserves for general and auto liability claims by approximately $3 million, based on obtaining an actuarial estimate of the unpaid loss attributed to general and auto liability claims for DPL at June 30, 2011.

Consolidation of Variable Interest Entities – DPL Renewable Energy Transactions

DPL is subject to Renewable Energy Portfolio Standards (RPS) in the state of Delaware that require it to obtain renewable energy credits (RECs) for energy delivered to its customers. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its customers by law. PHI, through its DPL subsidiary, has entered into three land-based wind power purchase agreements (PPAs) and one offshore wind PPA in the aggregate amount of 328 megawatts and one solar PPA with a 10 megawatt facility as of September 30, 2011. As the wind facilities become operational, DPL is obligated to purchase energy and RECs in amounts generated and delivered by the facilities at rates that are primarily fixed under these agreements. Under one of the PPAs, DPL is also obligated to purchase the capacity associated with the facility at rates that are generally fixed. If a wind facility does not become operational by a specified date, DPL has the right to terminate that PPA. DPL concluded that consolidation is not required for any of these agreements under FASB guidance on the consolidation of variable interest entities.

Two of the land-based facilities are operational and DPL is obligated to purchase energy and RECs from one of these facilities through 2024 in amounts not to exceed 50.25 megawatts and the second of these facilities through 2031 in amounts not to exceed 40 megawatts. DPL’s purchases under the operational wind PPAs totaled $3 million and $2 million for the three months ended September 30, 2011 and 2010, respectively, and $12 million and $8 million for the nine months ended September 30, 2011 and 2010, respectively. The other land-based wind agreement has a 20-year term and the facility is currently expected to become operational

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during 2011. In July 2011, the Delaware Public Service Commission (DPSC) approved amendments to this land-based wind PPA to change the location of the facility and to reduce the maximum generation capacity from 60 megawatts to 38 megawatts.

The offshore wind facility is expected to become operational during 2016. If the offshore wind facility developer is unable to obtain all necessary permits and financing commitments, this could result in delays in the construction schedule and the operational start date of the offshore wind facility.

The solar facility began operations in the third quarter of 2011. The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase RECs in an amount up to 70 percent of the energy output at a fixed price.DPL’s purchases under the agreement were $1 million during the third quarter of 2011.

On October 18, 2011, the DPSC approved a tariff submitted by DPL specific to a 30 megawatt fuel cell facility to be constructed using fuel cells manufactured in the State of Delaware. The RPS require that the DPSC establish an irrevocable tariff under which DPL would be an agent that collects payments from its customers and disburses the amounts collected to a Qualified Fuel Cell Provider that deploys Delaware-manufactured fuel cells as part of a 30 megawatt generation facility. The tariff and the RPS establish that DPL would be an agent to collect payments in advance from its distribution customers and remit them to the Qualified Fuel Cell Provider for each megawatt hour of energy produced over 20 years. DPL would have no liability to the Qualified Fuel Cell Provider other than to remit payments collected from its distribution customers pursuant to the tariff. The RPS provide for a reduction in DPL’s REC requirements based upon the actual energy output of the facility. PHI is currently assessing the appropriate accounting treatment for the transaction, including the applicability of FASB guidance on the consolidation of variable interest entities, leases, and derivative instruments. PHI’s accounting review is expected to be completed in the fourth quarter of 2011.

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. All of DPL’s goodwill was generated by DPL’s acquisition of Conowingo Power Company in 1995. DPL tests its goodwill for impairment annually and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of DPL below its carrying amount. DPL performs its annual impairment test on November 1. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; an adverse regulatory action; or an impairment of DPL’s long-lived assets. DPL concluded that an interim impairment test was not required during the three months ended September 30, 2011.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in DPL’s gross revenues were $4 million for each of the three months ended September 30, 2011 and 2010 and $14 million and $13 million for the nine months ended September 30, 2011 and 2010, respectively.

Reclassifications and adjustments

Certain prior period amounts have been reclassified to conform to current period presentation. The following adjustment has been recorded and is not considered material.

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Default Electricity Supply Revenue and Costs Adjustments

During 2011, DPL recorded adjustments associated with the accounting for Default Electricity Supply revenue and costs. These adjustments were primarily due to the under-recognition of allowed returns on working capital and administrative costs and resulted in a pre-tax decrease in Other operation and maintenance expense of $1 million and $9 million for the three and nine months ended September 30, 2011, respectively.

(3)NEWLY ADOPTED ACCOUNTING STANDARDS

Fair Value Measurements and Disclosures (Accounting Standards Codification (ASC) 820)

The FASB issued new disclosure requirements that require significant items within the reconciliation of the Level 3 valuation category to be presented in separate categories for purchases, sales, issuances and settlements. The guidance was effective beginning with DPL’s March 31, 2011 financial statements. DPL has included the new disclosure requirements in Note (11), “Fair Value Disclosures,” to its financial statements.

Goodwill (ASC 350)

The FASB issued new guidance on performing goodwill impairment tests that was effective beginning January 1, 2011 for DPL. Under the new guidance, the carrying value of the reporting unit must include the liabilities that are part of the capital structure of the reporting unit. DPL already allocates liabilities to the reporting unit when performing its goodwill impairment test, so the new guidance did not change DPL’s goodwill impairment test methodology.

(4)RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements and Disclosures (ASC 820)

In May 2011, the FASB issued new guidance on fair value measurement and disclosures that will be effective beginning with DPL’s March 31, 2012 financial statements. The new guidance will change how fair value is measured in specific instances and expand disclosures about fair value measurements. DPL is evaluating the impact of this new guidance on its financial statements.

Goodwill (ASC 350)

In September 2011, the FASB issued new guidance that changes the annual and interim assessments of goodwill for impairment. The new guidance modifies the required annual impairment test by giving entities the option to perform a qualitative assessment of whether it is more likely than not that goodwill is impaired before performing a quantitative assessment. The new guidance also amends the events and circumstances that entities should assess to determine whether an interim quantitative impairment test is necessary. The new guidance is effective beginning with DPL’s March 31, 2012 financial statements and DPL is evaluating the impact. The new guidance can be adopted prior to March 31, 2012, but DPL does not plan to employ the new qualitative assessment as part of its November 1, 2011 annual impairment test.

Compensation Retirement Benefits Multiemployer Plans (ASC 715-80)

In September 2011, the FASB issued new disclosure requirements for participants in multiemployer pension and postretirement benefit plans. The disclosures are intended to indicate the financial health of the plans and the potential future cash flow implications for participants in the plans. The new disclosures are effective beginning with DPL’s December 31, 2011 financial statements and prior periods presented. DPL is evaluating the impact of this new guidance on its financial statements.

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(5) SEGMENT INFORMATION

The company operates its business as one regulated utility segment, which includes all of its services as described above.

(6)GOODWILL

DPL’s goodwill balance of $8 million was unchanged during the three and nine months ended September 30, 2011. All of DPL’s goodwill was generated by its acquisition of Conowingo Power Company in 1995.

DPL’s annual impairment test as of November 1, 2010 indicated that goodwill was not impaired. For the three months ended September 30, 2011, DPL concluded that there were no events requiring it to perform an interim goodwill impairment test. DPL will perform its next annual impairment test as of November 1, 2011.

(7)PENSION AND OTHER POSTRETIREMENT BENEFITS

DPL accounts for its participation in its parent’s single-employer plans, the Pepco Holdings, Inc. Retirement Plan (the PHI Retirement Plan) and the Pepco Holdings, Inc. Welfare Plan for Retirees, as participation in multiemployer plans. PHI’s pension and other postretirement net periodic benefit cost for the three months ended September 30, 2011 and 2010, before intercompany allocations from the PHI Service Company, were $24 million and $26 million, respectively. DPL’s allocated share was $6 million and $7 million, respectively, for the three months ended September 30, 2011 and 2010. PHI’s pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2011 and 2010, before intercompany allocations from the PHI Service Company, were $70 million and $86 million, respectively. DPL’s allocated share was $18 million and $21 million, respectively, for the nine months ended September 30, 2011 and 2010.

On March 14, 2011, DPL made a discretionary tax-deductible contribution to the non-contributory PHI Retirement Plan of $40 million. DPL did not make a contribution to the PHI Retirement Plan in 2010.

(8)DEBT

Credit Facility

On August 1, 2011, PHI, Potomac Electric Power Company (Pepco), DPL and Atlantic City Electric Company (ACE) entered into an amendment and restatement of their $1.5 billion credit facility to extend the expiration date of the facility to August 1, 2016, and to make various other changes. As amended and restated, all or any portion of the facility may be used to obtain revolving loans and up to $500 million may be used to obtain letters of credit. PHI’s credit sublimit under the facility is $750 million and the sublimit of each of Pepco, DPL and ACE is $250 million. The borrowers may increase or decrease their respective sublimits during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of sublimit reallocations cannot exceed eight per fiscal year during the term of the agreement.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and one month LIBOR plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. The facility also includes a “swingline loan sub-facility,” pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt thereof. All indebtedness incurred under the facility is unsecured.

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At September 30, 2011 and December 31, 2010, the aggregate amount of cash plus unused borrowing capacity under the $1.5 billion credit facility available to meet the future liquidity needs of PHI’s utility subsidiaries was $831 million and $462 million, respectively.

(9)INCOME TAXES

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

	Three Months Ended September 30,									Nine Months Ended September 30,
	2011					2010				2011					2010
	(millions of dollars)
Income tax at federal statutory rate	$	7		35.0	%	$	6	35.0	%	$	31		35.0	%	$	18		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		1		5.2			1	5.0			5		5.3			3		5.2
Depreciation		—		(0.5	)		—	3.8			—		—			2		2.7
Tax credits		—		(1.0	)		—	(1.3	)		(1	)	(0.6	)		(1	)	(1.2	)
Change in estimates and interest related to uncertain and effectively settled tax positions		2		9.5			—	(0.6	)		(3	)	(3.1	)		1		2.1
Adjustments to prior year taxes		(1	)	(4.8	)		—	1.9			(1	)	(1.1	)		—		0.6
Other, net		1		4.2			—	—			1		0.9			—		(0.2	)
Income tax expense	$	10		47.6	%	$	7	43.8	%	$	32		36.4	%	$	23		44.2	%

Three Months Ended September 30, 2011 and 2010

DPL’s effective tax rates for the three months ended September 30, 2011 and 2010 were 47.6% and 43.8%, respectively. The increase in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions as well as adjustments to prior year taxes.

During the third quarter of 2011, DPL reached agreement with state taxing authorities related to certain state tax liabilities resulting in an increase to tax expense of $1 million (after-tax). Further, in the third quarter DPL recalculated interest on its uncertain tax positions for open tax years using different assumptions related to the application of its deposit made with the Internal Revenue Service in 2006. This resulted in an additional tax expense of $1 million (after-tax). Also during the third quarter DPL recorded a reduction to tax expense of $1 million (after-tax) related to certain non-recurring adjustments to prior year taxes.

Nine Months Ended September 30, 2011 and 2010

DPL’s effective tax rates for the nine months ended September 30, 2011 and 2010 were 36.4% and 44.2%, respectively. The decrease in the effective tax rate resulted from changes in estimates and interest related to uncertain and effectively settled tax positions, primarily related to the $2 million reversal of accrued interest income on state income tax positions recorded in 2010 that DPL no longer believes is more likely than not to be realized, and an additional $2 million interest benefit from the reallocation of deposits discussed below.

During the second quarter of 2011, PHI reached a settlement with the Internal Revenue Service (IRS) with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, DPL recorded additional interest income of $4 million (after-tax) in the second quarter of 2011. This benefit is partially offset by the adjustments recorded in the third quarter of 2011 related to DPL’s settlement with the state taxing authorities resulting in $1 million (after-tax) of

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additional tax expense and tax expense of $1 million associated with the recalculation of interest on uncertain tax positions for open tax years using different assumptions related to the application of its deposit made with the Internal Revenue Service in 2006.

(10)DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DPL uses derivative instruments in the form of swaps and over-the-counter options primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL also manages commodity risk with physical natural gas and capacity contracts that are not classified as derivatives. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered from its customers through a fuel adjustment clause approved by the DPSC.

The tables below identify the balance sheet location and fair values of derivative instruments as of September 30, 2011 and December 31, 2010:

	As of September 30, 2011
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative Liabilities (current liabilities)	$	(2	)	$	(13	)	$	(15	)	$	2	$	(13	)
Derivative Liabilities (non-current liabilities)		—			(5	)		(5	)		—		(5	)
Total Derivative Liabilities		(2	)		(18	)		(20	)		2		(18	)
Net Derivative (Liability) Asset	$	(2	)	$	(18	)	$	(20	)	$	2	$	(18	)

	As of December 31, 2010
Balance Sheet Caption	Derivatives Designated as Hedging Instruments			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative Liabilities (current liabilities)	$	(6	)	$	(15	)	$	(21	)	$	6	$	(15	)
Derivative Liabilities (non-current liabilities)		—			(8	)		(8	)		—		(8	)
Total Derivative Liabilities		(6	)		(23	)		(29	)		6		(23	)
Net Derivative (Liability) Asset	$	(6	)	$	(23	)	$	(29	)	$	6	$	(23	)

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Under FASB guidance on the offsetting of balance sheet accounts (ASC 210), DPL offsets the fair value amounts recognized for derivative instruments and fair value amounts recognized for related collateral positions executed with the same counterparty under master netting agreements. The amount of cash collateral that was offset against these derivative positions is as follows:

	September 30, 2011		December 31, 2010
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim	$	2	$	6

As of September 30, 2011 and December 31, 2010, all DPL cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.

Derivatives Designated as Hedging Instruments

Cash Flow Hedges

All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered from customers based on the fuel adjustment clause approved by the DPSC. The following table indicates the net unrealized derivative losses arising during the period included in regulatory assets and the realized losses recognized in the Statements of Income for the three and nine months ended September 30, 2011 and 2010 associated with cash flow hedges:

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2011			2010			2011			2010
	(millions of dollars)
Net Unrealized Losses arising during the period included in Regulatory Assets	$	(1	)	$	(3	)	$	(1	)	$	(9	)
Net Realized Losses Recognized in Purchased Energy or Gas Purchased		(2	)		(4	)		(5	)		(10	)

As of September 30, 2011 and December 31, 2010, DPL had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:

	Quantities
Commodity	September 30, 2011		December 31, 2010
Forecasted Purchases Hedges
Natural Gas (One Million British Thermal Units (MMBtu))		942,500		1,670,000

Effective October 1, 2011, DPL elected to no longer apply cash flow hedge accounting to its natural gas derivatives. These derivatives will continue to be employed as part of DPL’s natural gas hedging activities under the hedging program approved by the DPSC, and their dedesignation as cash flow hedges will not result in a change to the financial statement presentation because all of DPL’s gains and losses on these derivatives are recoverable from customers through the fuel adjustment clause approved by the DPSC.

Other Derivative Activity

DPL holds certain derivatives that are not in hedge accounting relationships nor are they designated as normal purchases or normal sales. These derivatives are recorded at fair value on the Balance Sheets with changes in the fair value recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory liabilities or regulatory assets are recorded on the Balance Sheets and the recognition of the

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derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause. For the three and nine months ended September 30, 2011 and 2010, the net unrealized derivative losses arising during the period included in regulatory assets and the net realized losses recognized in the Statements of Income are provided in the table below:

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2011			2010			2011			2010
	(millions of dollars)
Net Unrealized Losses arising during the period included in Regulatory Assets	$	(4	)	$	(9	)	$	(6	)	$	(21	)
Net Realized Losses Recognized in Purchased Energy or Gas Purchased		(3	)		(5	)		(14	)		(18	)

As of September 30, 2011 and December 31, 2010, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	September 30, 2011				December 31, 2010
Commodity	Quantity		Net Position		Quantity		Net Position
Natural Gas (MMBtu)		5,433,500		Long		7,827,635		Long

Contingent Credit Risk Features

The primary contracts used by DPL for derivative transactions are entered into under the International Swaps and Derivatives Association Master Agreement (ISDA) or similar agreements that closely mirror the principal credit provisions of the ISDA. The ISDAs include a Credit Support Annex (CSA) that governs the mutual posting and administration of collateral security. The failure of a party to comply with an obligation under the CSA, including an obligation to transfer collateral security when due or the failure to maintain any required credit support, constitutes an event of default under the ISDA for which the other party may declare an early termination and liquidation of all transactions entered into under the ISDA, including foreclosure against any collateral security. In addition, some of the ISDAs have cross default provisions under which a default by a party under another commodity or derivative contract, or the breach by a party of another borrowing obligation in excess of a specified threshold, is a breach under the ISDA.

Under the ISDA or similar agreements, the parties establish a dollar threshold of unsecured credit for each party in excess of which the party would be required to post collateral to secure its obligations to the other party. The amount of the unsecured credit threshold varies according to the senior, unsecured debt rating of the respective parties or that of a guarantor of the party’s obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on-balance sheet as well as those designated as normal purchases and normal sales that are accounted for off-balance sheet. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of DPL are stand-alone obligations without the guaranty of PHI. If DPL’s credit rating were to fall below “investment grade,” the unsecured credit threshold would typically be zero and collateral would be required for the entire net loss position. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder.

The gross fair value of DPL’s derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit-risk-related contingent features on September 30, 2011 and December 31, 2010, was $18 million and $23 million, respectively, before giving effect to the impact of a credit rating downgrade that would increase this amount or offsetting transactions that are encompassed within master netting agreements that would alter these amounts. As of those dates, DPL had not posted any

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cash collateral against the gross derivative liability. DPL’s net settlement amount in the event of a downgrade of DPL’s senior unsecured debt rating to below “investment grade” as of September 30, 2011 and December 31, 2010, would have been approximately $18 million and $37 million, respectively, after taking into account the master netting agreements.

DPL’s primary source for posting cash collateral or letters of credit are PHI’s credit facilities. At September 30, 2011 and December 31, 2010, the aggregate amount of cash plus borrowing capacity under the PHI credit facilities available to meet the liquidity needs of PHI’s utility subsidiaries was $831 million and $462 million, respectively.

(11) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

DPL applies FASB guidance on fair value measurement and disclosures (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). DPL utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, DPL utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance 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) and the lowest priority to unobservable inputs (level 3). DPL classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation 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, such as the New York Mercantile Exchange (NYMEX).

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 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 and 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.

Derivative instruments categorized as level 3 include natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC. The valuation of the options is based, in part, on internal volatility assumptions extracted from historical NYMEX prices over a certain period of time.

Executive deferred compensation plan assets and liabilities that are classified as level 3 include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies, which does not represent a quoted price in an active market.

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The following tables set forth, by level within the fair value hierarchy, DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2011 and December 31, 2010. As required by the guidance, 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 the exercise of 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 September 30, 2011
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Executive deferred compensation plan assets
Money Market Funds	$	2	$	2	$	—	$	—
Life Insurance Contracts		1		—		—		1
	$	3	$	2	$	—	$	1
LIABILITIES
Derivative instruments (b)
Natural Gas	$	20	$	2	$	—	$	18
	$	20	$	2	$	—	$	18

(a) There were no significant transfers of instruments between level 1 and level 2 valuation categories.

(b) The fair value of derivative liabilities reflects netting by counterparty before the impact of collateral.

	Fair Value Measurements at December 31, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Executive deferred compensation plan assets
Money Market Funds	$	2	$	2	$	—	$	—
Life Insurance Contracts		1		—		—		1
	$	3	$	2	$	—	$	1
LIABILITIES
Derivative instruments (b)
Natural Gas	$	29	$	6	$	—	$	23
	$	29	$	6	$	—	$	23

(a) There were no significant transfers of instruments between level 1 and level 2 valuation categories.

(b) The fair value of derivative liabilities reflects netting by counterparty before the impact of collateral.

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Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (level 3) for the nine months ended September 30, 2011 and 2010 are shown below:

	Nine Months Ended September 30, 2011
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(23	)	$	1
Total gains or (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory assets		(6	)		—
Purchases		—			—
Issuances		—			—
Settlements		11			—
Transfers in (out) of level 3		—			—
Ending balance as of September 30	$	(18	)	$	1

	Nine Months Ended September 30, 2010
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(29	)	$	1
Total gains or (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory assets		(21	)		—
Purchases		—			—
Issuances		—			—
Settlements		18			—
Transfers in (out) of level 3		—			—
Ending balance as of September 30	$	(32	)	$	1

Other Financial Instruments

The estimated fair values of DPL’s issued debt instruments as of September 30, 2011 and December 31, 2010 are shown below:

	September 30, 2011				December 31, 2010
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	765	$	837	$	765	$	822

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The fair value of long-term debt issued by DPL was based on actual trade prices as of September 30, 2011 and December 31, 2010. Where trade prices were not available, DPL used a discounted cash flow model and other valuation methodologies deemed appropriate by management to estimate fair value.

The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.

(12)COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Rate Proceedings

Over the last several years, DPL has proposed in each of their respective service territories the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date:

• A bill stabilization adjustment (BSA) has been approved and implemented for electric service in Maryland. The Maryland Public Service Commission (MPSC) has initiated a proceeding to review how the BSA operates in Maryland to recover revenues lost as a result of major storm outages (as discussed below).

• A modified fixed variable rate design (MFVRD) has been approved in concept for electric service in Delaware, but the implementation has been deferred by the DPSC pending the development of an implementation plan and a customer education plan. DPL anticipates that the MFVRD will be in place for electric service by early 2013.

• A MFVRD has been approved in concept for DPL natural gas service in Delaware, but implementation likewise has been deferred until development of an implementation plan and a customer education plan. DPL anticipates that the MFVRD will be in place for natural gas service by early 2013.

Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The MFVRD approved in concept in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption) to recover the utility’s fixed costs, plus a reasonable rate of return.

On February 1, 2011, the MPSC initiated proceedings involving DPL, as well as Pepco and unaffiliated utilities including Baltimore Gas & Electric Company and Southern Maryland Electric Cooperative, for the purpose of reviewing how the BSA operates to recover revenues lost as a result of major storm outages. In its orders initiating the proceedings, the MPSC expressed concern that the utilities’ respective BSAs may be allowing them to recover revenues lost during extended outages, therefore unintentionally eliminating an incentive to restore service quickly. The MPSC will consider whether the BSA, as currently in effect, is appropriate, whether the calculations or determinant factors for calculating the BSA should be modified, and if so, what modifications should be made. On July 22, 2011, the MPSC held a legislative-style hearing on this matter. A provision that excludes revenues lost as a result of major storm outages from the calculation of future BSA adjustments is already included in the BSA for Pepco in the District of Columbia as approved by the District of Columbia Public Service Commission. If the MPSC were to implement a change similar to the provision in effect in the District of Columbia, the financial impact of service interruptions due to a major storm would generally depend on the scope and duration of the outages. The potential financial impact of any modification to the BSA cannot be assessed until the details of the modification are known.

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Delaware

DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover gas procurement costs through customer rates. In August 2010, DPL made its 2010 GCR filing, which proposes rates that would allow DPL to recover an amount equal to a two-year amortization of currently under-recovered gas costs. In October 2010, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2010, subject to refund and pending final DPSC approval. The effect of the proposed two-year amortization upon rates is an increase of 0.1% in the level of GCR. The parties in the proceeding submitted a proposed settlement to the hearing examiner on June 3, 2011, which includes the first year of DPL’s two-year amortization but provides that DPL will forego the interest (a total of $342,000 for the two-year period 2011 to 2013) associated with that amortization. The proposed settlement was approved by the DPSC on October 18, 2011.

In August 2011, DPL made its 2011 GCR filing. The filing includes the second year of the effect of the proposed two-year amortization as proposed in DPL’s 2010 filing. On September 20, 2011, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2011, subject to refund and pending final DPSC approval.

In July 2010, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. As subsequently amended, the filing sought approval of an annual rate increase of approximately $10.2 million, assuming the implementation of the MFVRD, based on a requested return on equity (ROE) of 11.00%. As permitted by Delaware law, DPL placed an annual increase of approximately $2.5 million into effect, on a temporary basis, on August 31, 2010, and the remainder of approximately $7.7 million of the requested increase was placed into effect on February 2, 2011, in each case subject to refund and pending final DPSC approval. On June 21, 2011, the DPSC approved a settlement providing for an annual rate increase of approximately $5.8 million, based on an ROE of 10% (which was memorialized in an order issued August 9, 2011). The decision deferred the implementation of the MFVRD until an implementation plan and a customer education plan are developed. As of September 30, 2011, the amount collected in excess of the approved rate has been refunded to customers through a bill credit.

Maryland

On December 21, 2010, DPL filed an application with the MPSC to increase its electric distribution base rates by $17.8 million annually, based on an ROE of 10.75%. On May 25, 2011, DPL and the other parties to the proceeding filed a unanimous stipulation and settlement providing for a rate increase of approximately $12.2 million and proposing a Phase II proceeding to explore methods to address the issue of regulatory lag (which is the delay experienced by DPL in recovering increased costs in its distribution rate base). Although no ROE was specified in the proposed settlement, it did provide that the ROE for purposes of calculating the allowance for funds used during construction and regulatory asset carrying costs would remain unchanged. The current ROE for those items is 10%. On July 8, 2011, the MPSC approved the proposed settlement. On October 17, 2011, the parties notified the MPSC that they were unable to reach an agreement on the regulatory lag issues in the Phase II proceeding. DPL will pursue a regulatory lag mitigation mechanism in its upcoming rate case filing.

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. 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.

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Ward Transformer Site. In April 2009, a group of potentially responsible parties (PRPs) with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including DPL with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. With input from the court, the parties are discussing the next step in the litigation, which is likely to be the filing of summary judgment motions regarding liability for certain “test case” defendants other than DPL. The case is expected to be stayed as to the remaining defendants pending rulings upon the test cases. Although the magnitude of the potential liability at this site is not known at this time, DPL does not believe that it had extensive business transactions, if any, with the Ward Transformer site and therefore, costs incurred to resolve this matter are not expected to be material.

Indian River Oil Release. In 2001, DPL entered into a consent agreement with the Delaware Department of Natural Resources and Environmental Control for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination resulting from an oil release at the Indian River generating facility, which was sold in June 2001. As of September 30, 2011, DPL’s accrual for expected future costs to fulfill its obligations under the consent agreement was approximately $5 million, of which approximately $1 million is expected to be incurred during the remainder of 2011.

(13) RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including DPL. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to DPL for the three months ended September 30, 2011 and 2010 were approximately $35 million and $38 million, respectively. PHI Service Company costs directly charged or allocated to DPL for the nine months ended September 30, 2011 and 2010 were approximately $97 million and $103 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 Income:

Income (Expenses)	Three Months  Ended September 30,					Nine Months  Ended September 30,
	2011		2010			2011		2010
	(millions of dollars)
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (CESI) (a) (b)	$	—	$	(37	)	$	1	$	(76	)
Intercompany lease transactions (c)		1		1			3		5

(a) Included in purchased energy expense.

(b) During 2010, PHI disposed of its Conectiv Energy segment and a third party assumed CESI’s responsibilities under these contracts.

(c) Included in electric revenue.

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As of September 30, 2011 and December 31, 2010, DPL had the following balances on its Balance Sheets due (to) from related parties:

(Liability) Asset	September 30, 2011			December 31, 2010
	(millions of dollars)
(Payable to) Receivable from Related Party (a)
PHI Service Company	$	(19	)	$	(19	)
Conectiv Energy Supply, Inc.		—			(13	)
Pepco Energy Services Inc. (b)		(1	)		(2	)
Total	$	(20	)	$	(34	)
Money Pool Balance with Pepco Holdings (included in cash and cash equivalents)	$	10		$	63

(a) These amounts are included in Accounts payable due to associated companies on the Balance Sheets.

(b) DPL bills customers on behalf of Pepco Energy Services where customers have selected Pepco Energy Services as their alternative energy supplier.

(14)RESTRUCTURING CHARGE

With the ongoing wind down of the retail energy supply business of Pepco Energy Services and the disposition of Conectiv Energy Holding Company, PHI repositioned itself as a regulated transmission and distribution company during 2010. In connection with this repositioning, PHI completed a comprehensive organizational review in 2010 that identified opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments, which resulted in the adoption of a restructuring plan. PHI began implementation of the plan during 2010, identifying 164 employee positions that were eliminated. The plan also includes additional cost reduction opportunities that are being implemented through process improvements and operational efficiencies.

In connection with the restructuring plan, DPL recorded a pre-tax restructuring charge related to its allocation of severance, pension, and health and welfare benefits for the termination of corporate services employees at PHI of $8 million in 2010, of which $4 million was recorded in the three and nine months ended September 30, 2010. The severance, pension, and health and welfare benefits were estimated based on the years of service and compensation levels of the employees associated with the 164 eliminated positions at PHI. The restructuring charge was reflected as a separate line item in the Statement of Income for the year ended December 31, 2010.

A reconciliation of DPL’s accrued restructuring charges for the three and nine months ended September 30, 2011 is as follows:

	Three Months Ended September 30, 2011
	(millions of dollars)
Beginning balance as of July 1, 2011	$	2
Restructuring charge		—
Cash payments		(1	)
Ending balance as of September 30, 2011	$	1

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	Nine Months Ended September 30, 2011
	(millions of dollars)
Beginning balance as of January 1, 2011	$	7
Restructuring charge		—
Cash payments		(6	)
Ending balance as of September 30, 2011	$	1

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months  Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(millions of dollars)
Operating Revenue	$	399		$	518		$	1,018		$	1,150
Operating Expenses
Purchased energy		254			341			648			819
Other operation and maintenance		61			54			167			151
Restructuring charge		—			3			—			3
Depreciation and amortization		41			32			107			81
Other taxes		8			8			19			20
Deferred electric service costs		(17	)		13			(49	)		(69	)
Total Operating Expenses		347			451			892			1,005
Operating Income		52			67			126			145
Other Income (Expenses)
Interest expense		(18	)		(17	)		(51	)		(49	)
Other income		—			—			2			1
Total Other Expenses		(18	)		(17	)		(49	)		(48	)
Income Before Income Tax Expense		34			50			77			97
Income Tax Expense		17			20			36			43
Net Income		17			30			41			54
Retained Earnings at Beginning of Period		185			167			161			143
Retained Earnings at End of Period	$	202		$	197		$	202		$	197

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

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CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2011			December 31, 2010
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	91		$	4
Restricted cash equivalents		16			11
Accounts receivable, less allowance for uncollectible accounts of $12 million and $11 million, respectively		224			212
Inventories		24			17
Prepayments of income taxes		28			55
Income taxes receivable		5			25
Prepaid expenses and other		36			9
Total Current Assets		424			333
INVESTMENTS AND OTHER ASSETS
Regulatory assets		661			667
Prepaid pension expense		74			51
Income taxes receivable		61			59
Restricted cash equivalents		11			5
Assets and accrued interest related to uncertain tax positions		35			38
Other		14			11
Total Investments and Other Assets		856			831
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,515			2,443
Accumulated depreciation		(758	)		(729	)
Net Property, Plant and Equipment		1,757			1,714
TOTAL ASSETS	$	3,037		$	2,878

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

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CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2011		December 31, 2010
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	23	$	181
Current portion of long-term debt		37		35
Accounts payable and accrued liabilities		132		120
Accounts payable due to associated companies		15		29
Taxes accrued		9		7
Interest accrued		21		13
Other		40		41
Total Current Liabilities		277		426
DEFERRED CREDITS
Regulatory liabilities		67		71
Deferred income taxes, net		696		659
Investment tax credits		7		8
Other postretirement benefit obligations		31		27
Other		17		13
Total Deferred Credits		818		778
LONG-TERM LIABILITIES
Long-term debt		832		633
Transition Bonds issued by ACE Funding		306		332
Total Long-Term Liabilities		1,138		965
COMMITMENTS AND CONTINGENCIES (NOTE 11)
REDEEMABLE SERIAL PREFERRED STOCK		—		6
EQUITY
Common stock, $3.00 par value, 25,000,000 shares authorized, 8,546,017 shares outstanding		26		26
Premium on stock and other capital contributions		576		516
Retained earnings		202		161
Total Equity		804		703
TOTAL LIABILITIES AND EQUITY	$	3,037	$	2,878

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2011			2010
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	41		$	54
Adjustments to reconcile net income to net cash from (used by) operating activities:
Depreciation and amortization		107			81
Deferred income taxes		39			15
Changes in:
Accounts receivable		(12	)		(75	)
Inventories		(7	)		—
Regulatory assets and liabilities, net		(58	)		(70	)
Accounts payable and accrued liabilities		(2	)		(25	)
Pension contributions		(30	)		—
Prepaid New Jersey sales and excise tax		(49	)		(45	)
Taxes accrued		73			64
Other assets and liabilities		20			11
Net Cash From Operating Activities		122			10
INVESTING ACTIVITIES
Investment in property, plant and equipment		(96	)		(110	)
Department of Energy capital reimbursement awards received		3			—
Net other investing activities		(11	)		(3	)
Net Cash Used By Investing Activities		(104	)		(113	)
FINANCING ACTIVITIES
Capital contribution from Parent		60			43
Redemption of preferred stock		(6	)		—
Issuances of long-term debt		200			23
Reacquisition of long-term debt		(25	)		(25	)
(Repayments) issuances of short-term debt, net		(158	)		63
Net other financing activities		(2	)		—
Net Cash From Financing Activities		69			104
Net Increase in Cash and Cash Equivalents		87			1
Cash and Cash Equivalents at Beginning of Period		4			7
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	91		$	8
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes (includes payments from PHI for federal income taxes)	$	51		$	2

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ATLANTIC CITY ELECTRIC COMPANY

(1)ORGANIZATION

Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey. ACE also 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 energy supplier. Default Electricity Supply is known as Basic Generation Service in New Jersey. ACE is a wholly owned subsidiary of Conectiv, LLC, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).

(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, 2010. In the opinion of ACE’s management, the Consolidated Financial Statements contain all adjustments (which all are of a normal recurring nature) necessary to state fairly ACE’s financial condition as of September 30, 2011, in accordance with GAAP. The year-end December 31, 2010 Consolidated Balance Sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and nine months ended September 30, 2011 may not be indicative of results that will be realized for the full year ending December 31, 2011 since the sales of electric energy are seasonal.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the Consolidated Financial Statements and accompanying notes. Although ACE believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.

Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, unbilled revenue calculations, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of restructuring charges, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto liability claims and income tax provisions and reserves. Additionally, ACE is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. ACE records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.

Storm Costs

During the third quarter of 2011, ACE incurred significant costs associated with Hurricane Irene that affected its service territory. Total incremental storm costs associated with Hurricane Irene were $13 million, with $7 million incurred for repair work and $6 million incurred as capital expenditures. All costs incurred for repair work were deferred as a regulatory asset to reflect

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the probable recovery of these storm costs. Approximately $8 million of these total incremental storm costs have been estimated for the cost of restoration services provided by outside contractors since a large portion of the invoices for such services had not been received at September 30, 2011. Actual invoices may vary from these estimates. ACE currently plans to seek recovery of the incremental Hurricane Irene costs as discussed in Note (11), “Commitments and Contingencies—Rate Proceedings.”

Network Service Transmission Rates

In May 2011, ACE filed its network service transmission rates with the Federal Energy Regulatory Commission effective for the service year beginning June 1, 2011. The new rates include an adjustment for costs incurred in the service year ended May 31, 2011 that were not reflected in the rates charged to customers for that service year. In the second quarter of 2011, ACE recorded a $1 million increase in transmission revenues as a change to the estimates recorded in previous periods primarily due to an increase in the actual rate base versus the estimated rate base.

For the nine months ended September 30, 2010, ACE recorded a $2 million increase in transmission service revenue associated with a change to the estimates recorded in previous periods.

General and Auto Liability

During the second quarter of 2011, ACE reduced its self-insurance reserves for general and auto liability claims by approximately $1 million, based on obtaining an actuarial estimate of the unpaid loss attributed to general and auto liability claims for ACE at June 30, 2011.

Consolidation of Variable Interest Entities

ACE Power Purchase Agreements (PPAs)

ACE is a party to three PPAs with unaffiliated, non-utility generators (NUGs). ACE was unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary and as a result has applied the scope exemption from the consolidation guidance for enterprises that have not been able to obtain such information.

Net purchase activities with the NUGs for the three months ended September 30, 2011 and 2010 were approximately $57 million and $82 million, respectively, of which approximately $55 million and $74 million, respectively, consisted of power purchases under the PPAs. Net purchase activities with the NUGs for the nine months ended September 30, 2011 and 2010 were approximately $169 million and $222 million, respectively, of which approximately $159 million and $203 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACE’s customers through regulated rates.

Atlantic City Electric Transition Funding LLC

Atlantic City Electric Transition Funding LLC (ACE Funding) was established in 2001 by ACE solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of bonds (Transition Bonds). The proceeds of the sale of each series of Transition Bonds have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect non-bypassable transition bond charges (the Transition Bond Charges) from ACE customers pursuant to bondable stranded costs rate orders issued by the New Jersey Board of Public Utilities (NJBPU) in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). ACE collects the Transition Bond Charges from its customers on behalf of ACE Funding and the holders of the Transition Bonds. The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from

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ACE’s customers, are not available to creditors of ACE. The holders of the Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding and consolidates ACE Funding in its financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

ACE Standard Offer Capacity Agreements

On April 28, 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. The SOCAs were established under a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey. The SOCAs are 15-year, financially settled transactions approved by the NJBPU that allow generators to receive payments from, or make payments to, ACE based on the difference between the fixed price in the SOCAs and the price for capacity that clears PJM Interconnection, LLC (PJM). Each of the other electricity distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. The annual share of payments or receipts for ACE and the other EDCs is based upon each company’s annual proportion of the total New Jersey load attributable to all EDCs. ACE and the other EDCs entered the SOCAs under protest based on concerns about the potential cost to distribution customers. In February 2011, ACE joined other plaintiffs in an action filed in the United States District Court for the District of New Jersey challenging the constitutionality of the New Jersey law. The proceeding is now in the discovery phase. In May 2011, the NJBPU denied a joint motion for reconsideration of its order requiring each of the EDCs to enter into the SOCAs. In June 2011, ACE and the other EDCs filed appeals related to the NJBPU orders with the Appellate Division of the New Jersey Superior Court.

On October 17, 2011, one of the generation companies sent a notice of dispute under the SOCA to ACE. The notice of dispute alleges that certain actions taken by PJM have an adverse effect on the generation company’s ability to clear the PJM auction as required by the SOCA and, under a provision of the SOCA, ACE and the generation supplier must attempt to amend the SOCA in order to permit transactions to continue thereunder, subject to NJBPU approval. ACE has agreed to meet with the generation supplier, but does not acknowledge that a “dispute” exists under the SOCA.

Currently, PHI believes that Financial Accounting Standards Board (FASB) guidance on derivative accounting and the accounting for regulated operations would apply to a SOCA once capacity has cleared a PJM auction. Once cleared, the gain (loss) associated with the fair value of a derivative would be offset by the establishment of a regulatory liability (asset).

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were $7 million and $8 million for the three months ended September 30, 2011 and 2010, and $17 million and $18 million for the nine months ended September 30, 2011 and 2010.

Reclassifications and Adjustments

Certain prior period amounts have been reclassified in order to conform to the current period presentation. The following adjustments have been recorded and are not considered material either individually or in the aggregate:

Income Tax Adjustments

During the second quarter of 2011, ACE completed a reconciliation of its deferred taxes associated with certain regulatory assets and recorded adjustments which resulted in an increase to income tax expense of $1 million for the nine months ended September 30, 2011.

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During the first quarter of 2010, ACE recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment resulted in an increase in income tax expense of $6 million for the nine months ended September 30, 2010. The adjustment represents the reversal of erroneously recorded interest income for state income tax purposes related to uncertain and effectively settled tax positions, including $2 million, $3 million and $1 million recorded in 2009, 2008 and 2007, respectively.

(3)NEWLY ADOPTED ACCOUNTING STANDARDS

Fair Value Measurements and Disclosures (Accounting Standards Codification (ASC) 820)

The FASB issued new disclosure requirements that require significant items within the reconciliation of the Level 3 valuation category to be presented in separate categories for purchases, sales, issuances and settlements. The guidance was effective beginning with ACE’s March 31, 2011 financial statements. ACE has included the new disclosure requirements in Note (10), “Fair Value Disclosures,” to its consolidated financial statements.

(4)RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Fair Value Measurements and Disclosures (ASC 820)

In May 2011, the FASB issued new guidance on fair value measurement and disclosures that will be effective beginning with ACE’s March 31, 2012 consolidated financial statements. The new guidance will change how fair value is measured in specific instances and expand disclosures about fair value measurements. ACE is evaluating the impact of this new guidance on its consolidated financial statements.

Compensation Retirement Benefits Multiemployer Plans (ASC 715-80)

In September 2011, the FASB issued new disclosure requirements for participants in multiemployer pension and postretirement benefit plans. The disclosures are intended to indicate the financial health of the plans and the potential future cash flow implications for participants in the plans. The new disclosures are effective beginning with ACE’s December 31, 2011 consolidated financial statements and prior periods presented. ACE is evaluating the impact of this new guidance on its consolidated financial statements.

(5) SEGMENT INFORMATION

The company operates its business as one regulated utility segment, which includes all of its services as described above.

(6) PENSION AND OTHER POSTRETIREMENT BENEFITS

ACE accounts for its participation in its parent’s single-employer plans, the Pepco Holdings, Inc. Retirement Plan (the PHI Retirement Plan) and the Pepco Holdings, Inc. Welfare Plan for Retirees, as participation in multiemployer plans. PHI’s pension and other postretirement net periodic benefit cost for the three months ended September 30, 2011 and 2010, before intercompany allocations from the PHI Service Company, were $24 million and $26 million, respectively. ACE’s allocated share was $5 million and $6 million, respectively, for the three months ended September 30, 2011 and 2010. PHI’s pension and other postretirement net periodic benefit cost for the nine months ended September 30, 2011 and 2010, before intercompany allocations from the PHI Service Company, were $70 million and $86 million, respectively. ACE’s allocated share was $15 million and $17 million, respectively, for the nine months ended September 30, 2011 and 2010.

On March 14, 2011, ACE made a discretionary tax-deductible contribution to the non-contributory PHI Retirement Plan of $30 million. ACE did not make a contribution to the PHI Retirement Plan in 2010.

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(7) DEBT

Credit Facility

On August 1, 2011, PHI, Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and ACE entered into an amendment and restatement of their $1.5 billion credit facility to extend the expiration date to August 1, 2016, and to make various other changes. As amended and restated, all or any portion of the facility may be used to obtain revolving loans and up to $500 million may be used to obtain letters of credit. PHI’s credit sublimit under the facility is $750 million and the sublimit of each of Pepco, DPL and ACE is $250 million. The borrowers may increase or decrease their respective sublimits during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of sublimit reallocations cannot exceed eight per fiscal year during the term of the agreement.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and one month LIBOR plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower. The facility also includes a “swingline loan sub-facility,” pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt thereof. All indebtedness incurred under the facility is unsecured.

At September 30, 2011 and December 31, 2010, the aggregate amount of cash plus unused borrowing capacity under the $1.5 billion credit facility available to meet the future liquidity needs of PHI’s utility subsidiaries was $831 million and $462 million, respectively.

Financing Activities

In July 2011, ACE Funding made principal payments of $6 million on its Series 2002-1 Bonds, Class A-3, and $2 million on its Series 2003-1 Bonds, Class A-2.

Financing Activities Subsequent to September 30, 2011

In October 2011, ACE Funding made principal payments of $8 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

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(8) INCOME TAXES

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

	Three Months Ended September 30,										Nine Months Ended September 30,
	2011					2010					2011					2010
Income tax at federal statutory rate	$	12		35.0	%	$	18		35.0	%	$	27		35.0	%	$	34		35.0	%
Increases (decreases) resulting from:
State income taxes, net of federal effect		2		4.4			3		6.6			5		5.9			7		6.8
Change in estimates and interest related to uncertain and effectively settled tax positions		4		10.5			(1	)	(1.2	)		4		5.1			4		3.7
Deferred tax adjustment		—		—			—		—			1		1.7			—		—
Other, net		(1	)	0.1			—		(0.4	)		(1	)	(0.9	)		(2	)	(1.2	)
Consolidated income tax expense	$	17		50.0	%	$	20		40.0	%	$	36		46.8	%	$	43		44.3	%

Three Months Ended September 30, 2011 and 2010

ACE’s consolidated effective tax rates for the three months ended September 30, 2011 and 2010 were 50.0% and 40.0%, respectively. The increase in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions.

During the third quarter of 2011 the company recalculated interest on its uncertain tax positions for open tax years using different assumptions related to the application of its deposit made with the Internal Revenue Service in 2006. This resulted in an additional tax expense of $3 million (after-tax).

Nine Months Ended September 30, 2011 and 2010

ACE’s consolidated effective tax rates for the nine months ended September 30, 2011 and 2010 were 46.8% and 44.3%, respectively. The increase in the effective tax rate primarily resulted from ACE’s reconciliation of deferred taxes on certain regulatory assets which resulted in a $1 million increase to income tax expense included in the deferred tax adjustment and changes in estimates and interest related to uncertain and effectively settled tax positions.

During the second quarter of 2011, PHI reached a settlement with the Internal Revenue Service (IRS) with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, ACE has recorded an additional $1 million (after-tax) of interest due to the IRS. This additional interest expense was recorded in the second quarter of 2011. This is further impacted by the adjustment recorded in the third quarter of 2011 related to the recalculation of interest on its uncertain tax positions for open tax years using different assumptions related to the application of its deposit made with the Internal Revenue Service in 2006.

Also, during the first quarter of 2010, ACE recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment resulted in an increase in income tax expense of $6 million for the nine months ended September 30, 2010. The adjustment represents the reversal of erroneously recorded interest income for state income tax purposes related to uncertain and effectively settled tax positions, including $2 million, $3 million and $1 million recorded in 2009, 2008 and 2007, respectively.

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(9)PREFERRED STOCK

On February 25, 2011, ACE redeemed all of its outstanding cumulative preferred stock for approximately $6 million.

(10) FAIR VALUE DISCLOSURES

Financial Instruments Measured at Fair Value on a Recurring Basis

ACE applies FASB guidance on fair value measurement and disclosures (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, 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. The guidance 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) and the lowest priority to unobservable inputs (level 3). ACE classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation 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 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 and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.

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.

The following tables set forth, by level within the fair value hierarchy, ACE’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2011 and December 31, 2010. As required by the guidance, 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 the exercise of 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 September 30, 2011
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents
Treasury Fund	$	113	$	113	$	—	$	—
	$	113	$	113	$	—	$	—
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

(a) There were no significant transfers of instruments between level 1 and level 2 valuation categories.

	Fair Value Measurements at December 31, 2010
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
ASSETS
Cash equivalents
Treasury Fund	$	17	$	17	$	—	$	—
	$	17	$	17	$	—	$	—
LIABILITIES
Executive deferred compensation plan liabilities
Life Insurance Contracts	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

(a) There were no significant transfers of instruments between level 1 and level 2 valuation categories.

Other Financial Instruments

The estimated fair values of ACE’s issued debt and equity instruments at September 30, 2011 and December 31, 2010 are shown below:

	September 30, 2011				December 31, 2010
	(millions of dollars)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	832	$	981	$	633	$	710
Transition Bonds issued by ACE Funding		343		392		367		406
Redeemable Serial Preferred Stock		—		—		6		5

The fair value of long-term debt issued by ACE was based on actual trade prices as of September 30, 2011 and December 31, 2010. Where trade prices were not available, ACE used a discounted cash flow model and other valuation methodologies deemed appropriate by management to estimate fair value. The fair value of Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on actual trade prices as of September 30, 2011. Bid prices obtained from brokers and validated by PHI were used at December 31, 2010, because actual trade prices were not available.

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The fair value of the Redeemable Serial Preferred Stock was derived based on quoted market prices.

The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.

(11) COMMITMENTS AND CONTINGENCIES

Regulatory and Other Matters

Rate Proceedings

Over the last several years, ACE has proposed the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date, a bill stabilization adjustment (BSA) it proposed as part of a Phase 2 to the base rate proceeding filed in August 2009 was not included in the final settlement approved by the NJBPU on May 16, 2011. Accordingly, there is no BSA proposal currently pending in New Jersey. Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission.

On August 5, 2011, ACE filed a petition with the NJBPU to increase its electric distribution rates by the net amount of approximately $58.9 million, based on a return on equity of 10.75%. The net increase consists of a rate increase proposal of approximately $70.5 million, less a deduction from base rates of approximately $17 million attributable to excess depreciation expenses, plus approximately a $4.9 million increase in sales-and-use taxes and an upward adjustment of approximately $0.5 million in the Regulatory Asset Recovery Charge. ACE has requested that the rate increase be effective in May 2012.

In July 2009, the NJBPU approved certain rate recovery mechanisms in connection with ACE’s Infrastructure Investment Program (the IIP). In exchange for the increase in infrastructure investment, the NJBPU, through the IIP, allowed recovery of ACE’s infrastructure investment capital expenditures through a special rate outside the normal rate recovery mechanism of a base rate filing. The IIP is designed to stimulate the New Jersey economy and provide incremental employment in ACE’s service territory by increasing the level of infrastructure expenditures invested above otherwise normal budgeted levels. On October 18, 2011, ACE filed a petition with the NJBPU for approval of an extension and expansion to the IIP, which is intended to become effective on or about January 1, 2012, and remain in effect until December 31, 2014. In calendar year 2012, ACE proposes as part of the IIP to recover approximately $69 million in reliability-related capital expenditures out of total reliability-related annual capital expenditures of approximately $103 million. For calendar years 2013 and 2014, ACE proposes to recover IIP capital expenditures of approximately $94 million and $81 million, respectively. Capital expenditures related to the proposed special rate would be subject to annual reconciliation and approval by the NJBPU.

On August 26, 2011, ACE filed a petition with the NJBPU seeking authorization for deferred accounting treatment of uninsured incremental storm damage restoration costs not otherwise recovered through base rates. In this petition, ACE proposed that storm costs for each individual storm would qualify for deferred accounting if the storm causes disruption to service of 10% or more of ACE’s customers or if any of ACE’s customers are without utility service for more than 24 hours. The deferred accounting treatment would include recovery of such costs incurred during Hurricane Irene, which impacted ACE’s service territory in the third quarter of 2011.

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Environmental Litigation

ACE is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. 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.

Franklin Slag Pile Site. In November 2008, ACE received a general notice letter from the U.S. Environmental Protection Agency (EPA) concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983. EPA claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA letter also states that, as of the date of the letter, EPA’s expenditures for response measures at the site have exceeded $6 million. EPA estimates the cost for future response measures will be approximately $6 million. ACE believes that EPA sent similar general notice letters to three other companies and various individuals.

ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications and, therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE. Costs to resolve this matter are not expected to be material and are expensed as incurred.

Ward Transformer Site. In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including ACE with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. With input from the court, the parties are discussing the next step in the litigation, which is likely to be the filing of summary judgment motions regarding liability for certain “test case” defendants other than ACE. The case is expected to be stayed as to the remaining defendants pending rulings upon the test cases. Although the magnitude of the potential liability at this site is not known at this time, ACE does not believe that it had extensive business transactions, if any, with the Ward Transformer site and therefore, costs incurred to resolve this matter are not expected to be material.

Price’s Pit Site. ACE owns a transmission and distribution right-of-way that traverses the Price’s Pit superfund site in Egg Harbor Township, New Jersey. EPA placed Price’s Pit on the NPL in 1983 and the New Jersey Department of Environmental Protection (NJDEP) undertook an environmental investigation to identify and implement remedial action at the site. NJDEP’s investigation revealed that landfill waste had been disposed on ACE’s right-of-way and NJDEP determined that ACE was a responsible party as the owner of a facility on which a hazardous substance has been deposited. ACE, EPA and NJDEP entered into a settlement agreement effective on August 11, 2011 to resolve ACE’s alleged liability. The settlement agreement requires ACE to make a payment of approximately $1 million (the amount accrued

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by ACE in 2010) to the EPA Hazardous Substance Superfund, which has been paid, and donate a four-acre parcel of land adjacent to the site to NJDEP.

(12)RELATED PARTY TRANSACTIONS

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including ACE. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets, and other cost causal methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to ACE for the three months ended September 30, 2011 and 2010 were approximately $27 million and $28 million, respectively. PHI Service Company costs directly charged or allocated to ACE for the nine months ended September 30, 2011 and 2010 were approximately $75 million and $73 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 Income:

	Three Months  Ended September 30,						Nine Months  Ended September 30,
Income (Expense)	2011			2010			2011			2010
	(millions of dollars)
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (CESI) (a) (b)	$	—		$	(61	)	$	—		$	(141	)
Meter reading services provided by Millennium Account Services LLC (c)		(1	)		(1	)		(3	)		(3	)
Intercompany lease transactions (c)		—			—			(1	)		(1	)
Intercompany use revenue (d)		1			1			2			2

(a) Included in purchased energy expense.

(b) During 2010, PHI disposed of its Conectiv Energy segment and a third party assumed CESI’s responsibilities under these contracts.

(c) Included in other operation and maintenance expense.

(d) Included in operating revenue.

As of September 30, 2011 and December 31, 2010, ACE had the following balances on its Consolidated Balance Sheets due to related parties:

Liability	September 30, 2011			December 31, 2010
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(13	)	$	(13	)
CESI		—			(14	)
Other		(2	)		(2	)
Total	$	(15	)	$	(29	)

(a) These amounts are included in Accounts payable due to associated companies on the Consolidated Balance Sheets.

During the third quarter of 2011, PHI made a $60 million capital contribution to ACE.

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(13)RESTRUCTURING CHARGE

With the ongoing wind down of the retail energy supply business of Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services) and the disposition of Conectiv Energy Holding Company, PHI repositioned itself as a regulated transmission and distribution company during 2010. In connection with this repositioning, PHI completed a comprehensive organizational review in 2010 that identified opportunities to streamline the organization and to achieve certain reductions in corporate overhead costs that are allocated to its operating segments, which resulted in the adoption of a restructuring plan. PHI began implementation of the plan during 2010, identifying 164 employee positions that were eliminated. The plan also includes additional cost reduction opportunities that are being implemented through process improvements and operational efficiencies.

In connection with the restructuring plan, ACE recorded a pre-tax restructuring charge related to its allocation of severance, pension, and health and welfare benefits for the termination of corporate services employees at PHI of $6 million in 2010, of which $3 million was recorded in the three and nine months ended September 30, 2010. The severance, pension, and health and welfare benefits were estimated based on the years of service and compensation levels of the employees associated with the 164 eliminated positions at PHI. The restructuring charge was reflected as a separate line item in the Consolidated Statement of Income for the year ended December 31, 2010.

A reconciliation of ACE’s accrued restructuring charges for the three and nine months ended September 30, 2011 is as follows:

	Three Months Ended September 30, 2011
	(millions of dollars)
Beginning balance as of July 1, 2011	$	1
Restructuring charge		—
Cash payments		—
Ending balance as of September 30, 2011	$	1

	Nine Months Ended September 30, 2011
	(millions of dollars)
Beginning balance as of January 1, 2011	$	6
Restructuring charge		—
Cash payments		(5	)
Ending balance as of September 30, 2011	$	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		110
Pepco		147
DPL		157
ACE		168

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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 holding company that is engaged primarily in the transmission, distribution and default supply of electricity and the distribution and supply of natural gas through its regulated public utility subsidiaries (Power Delivery). Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy efficiency services primarily to government and institutional customers and is in the process of winding down its competitive electricity and natural gas retail supply business. Each of Power Delivery and Pepco Energy Services constitutes a separate segment for financial reporting purposes. A third segment, Other Non-Regulated, owns a portfolio of cross-border energy lease investments.

The following table sets forth the percentage contributions to consolidated operating revenue and consolidated operating income from continuing operations attributable to the Power Delivery, Pepco Energy Services and Other Non-Regulated segments. Power Delivery Electric consists primarily of the transmission, distribution and default supply of electricity, and Power Delivery Gas consists of the delivery and supply of natural gas.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Percentage of Consolidated Operating Revenue
Power Delivery		81	%		77	%		78	%		73	%
Pepco Energy Services		19	%		22	%		21	%		27	%
Other Non-Regulated		—			1	%		1	%		—
Percentage of Consolidated Operating Income
Power Delivery		83	%		86	%		76	%		80	%
Pepco Energy Services		6	%		7	%		8	%		12	%
Other Non-Regulated		11	%		7	%		16	%		8	%
Percentage of Power Delivery Operating Revenue
Power Delivery Electric		98	%		98	%		95	%		96	%
Power Delivery Gas		2	%		2	%		5	%		4	%

Power Delivery

The Power Delivery business is conducted by PHI’s three regulated public utility subsidiaries: Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL), and Atlantic City Electric Company (ACE). Each utility is regulated in the jurisdictions that comprise its service territory. Each utility is responsible for the distribution of electricity and, in the case of DPL, natural gas in its service territory, for which it is paid tariff rates established by the applicable local public service commission. Each utility 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 is Standard Offer Service (SOS) in Delaware, the District of Columbia and Maryland, and Basic Generation Service (BGS) in New Jersey. In this Form 10-Q, these supply service obligations are referred to generally as Default Electricity Supply.

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

The profitability of the Power Delivery business depends on its ability to recover costs and earn a reasonable return on its capital investments through the rates it is permitted to charge. The Power Delivery 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.

As a result of the implementation of a bill stabilization adjustment mechanism (BSA) for retail electric customers of Pepco and DPL in Maryland in June 2007 and for retail customers of Pepco in the District of Columbia in November 2009, Pepco and DPL recognize distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, this has the effect of decoupling distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a consequence, the only factors that will cause distribution revenue in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. For customers to whom the BSA applies, changes in customer usage (such as due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue.

Reliability Enhancement Plans

PHI continues to execute on its plans to enhance reliability at Pepco, DPL and ACE. This is a key driver for success in each of the applicable regulatory jurisdictions to improve the distribution system. The capital investment deemed necessary to improve reliability at Pepco, DPL and ACE is estimated at $1.7 billion for the period from 2012 through 2016. The amount of capital investment required at Pepco, DPL and ACE is estimated at approximately $900 million, $350 million and $400 million, respectively. The total amount of the expenditures may change when anticipated regulations imposing reliability standards are promulgated in Maryland and upon the completion of Pepco’s analysis of the recently adopted modifications to the reliability standards in the District of Columbia.

The reliability enhancement plan includes the identification and upgrading of under-performing feeder lines, the addition of new facilities to support load, the installation of distribution automation systems on both the overhead and underground network system, the rejuvenation and replacement of underground residential cables, improvements to substation supply lines and selective undergrounding of portions of existing above ground primary feeder lines, where appropriate to improve reliability. By continuing to focus on these areas, PHI plans to increase the reliability of the electric system by reducing both the frequency and duration of power outages.

Blueprint for the Future

Each of PHI’s three utilities are participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. The initiative includes the implementation of various programs to help customers better manage their energy use, reduce the total cost of energy and provide other benefits. These programs also allow each utility to better manage and operate its electrical and natural gas distribution systems.

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Significant developments initiated in 2011 include:

• On July 6, 2011, DPL filed its proposal in Delaware to establish a new residential air-conditioning cycle program, which, if approved, would launch in 2012.

• Full-scale implementation of Advanced Metering Infrastructure (AMI) began in the Pepco-Maryland service territory in June 2011.

• On June 15, 2011, Pepco filed a revised tariff in the District of Columbia related to the direct load control programs. This tariff proposes cost recovery through the establishment of a regulatory asset rather than a distribution bill surcharge.

• In March 2011, the Maryland Public Service Commission (MPSC) lifted the suspension on installation of smart thermostats for both DPL and Pepco in their Maryland service territories and accordingly smart thermostat installation has commenced.

• In March 2011, DPL filed its Dynamic Pricing proposal in Delaware. If approved, the program will begin in 2012 with a phase-in stage for customers who participated in the field acceptance tests for AMI.

MAPP Project

In October 2007, the PJM Interconnection, LLC (PJM) Board of Managers approved PHI’s proposal to construct a new 230-mile, 500-kilovolt interstate transmission line referred to as the Mid-Atlantic Power Pathway (MAPP), as part of PJM’s regional transmission expansion plan to address the reliability objectives of the PJM regional transmission organization (PJM RTO) system. Since that time, there have been various modifications to the proposal that have redefined the length and route of the MAPP project. PJM has approved the use of advanced direct current technology for segments of the project, including the portion of the line that will traverse under the Chesapeake Bay. The direct current portion of the line will be 640 kilovolts and the remainder of the line will be 500 kilovolts. As currently approved by the PJM Board of Managers, MAPP is approximately 152 miles in length originating at the Possum Point substation in Virginia and ending at the Indian River substation in Delaware. The cost of the MAPP project is currently estimated to be $1.2 billion.

On August 18, 2011, PJM notified PHI that the scheduled in-service date for MAPP has been delayed from June 1, 2015 to the 2019 to 2021 time period, to take into account changes in demand response, generation retirements and additions, as well as a revised load forecast for the PJM region that is lower than the load that was forecasted in prior PJM studies. PJM has retained the MAPP project in its 2011 Regional Transmission Expansion Plan (RTEP).

In light of the new in-service date, future revenues associated with the MAPP project would be delayed to later years. The MAPP project is anticipated to earn higher rates of return than PHI’s existing transmission assets. In addition, PHI has requested a temporary delay in the procedural schedules related to the pending applications to construct MAPP in filings with the MPSC and the Virginia State Corporation Commission (VSCC) to the later of one year from August 2011 or the issuance of the 2012 RTEP analysis related to MAPP. In the third quarter of 2011, the MPSC suspended the procedural schedule for MAPP until September 6, 2012. The VSCC has informally indicated to PHI that the VSCC will take no action on PHI’s application to construct MAPP in Virginia until further developments occur with respect to the MAPP project.

The exact revised in-service date of MAPP will be evaluated as part of PJM’s 2012 RTEP review process. Until PJM’s evaluation is concluded, PJM has directed PHI to limit further development efforts with respect to the MAPP project and to proceed with only those development efforts reasonably necessary to allow the MAPP project to be quickly restarted if and when deemed necessary. PHI will be evaluating the work that will be required to support MAPP based on the new in-service date and in accordance with the directives of PJM. During this interim period, PHI intends to continue to complete the right-of-way acquisition for the proposed route, and some environmental and other preparatory activities.

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Regulatory Lag

The regulatory commissions to which Pepco, DPL and ACE are subject were established to set utility rates and tariffs with respect to the retail distribution of electricity and natural gas. These rates are intended to be set, balancing the interests of the utilities’ customers and those of its investors. In order to achieve this balancing, the regulatory commissions must develop rates and tariffs that are reflective of costs during the period in which the rates are in effect, in order to give each utility the opportunity to generate revenues sufficient to recover its costs, including a reasonable rate of return on investor supplied capital during such period. In designing a utility’s rate structure, an important factor affecting each utility’s ability to earn its authorized rate of return is the willingness of applicable regulatory commissions to adequately recognize costs in such period in order to minimize the delay in recovering increased costs of distribution service. This delay in recovering such increased costs is commonly known as “regulatory lag.” All of PHI’s utilities are currently experiencing significant regulatory lag.

Higher operating and construction costs, including labor, material, depreciation, taxes and financing costs, as well as costs associated with enhanced distribution system reliability and environmental compliance, are expected at each of PHI’s utility subsidiaries for several years into the future. At the same time, low usage growth and customer growth limits the growth in revenues. This mismatch between high expense growth and low revenue growth increases regulatory lag at Pepco, DPL and ACE, making it more difficult for each utility to earn equity returns that are allowed by regulators without higher rates. See “Part II, Item 1A. Risk Factors—The failure of PHI to obtain relief from ‘regulatory lag’ may have a negative effect on PHI’s results of operations and financial condition.”

Pepco, DPL and ACE anticipate that they will continue to face regulatory lag. In their most recent rate cases, Pepco (in the District of Columbia) and DPL (in Maryland) each has proposed mechanisms that would track reliability and other expenses and permit the utility between rate cases to make adjustments in its rates for prudent investments as made, thereby seeking to reduce the magnitude of regulatory lag. Neither Maryland nor the District of Columbia has approved these proposed mechanisms. In New Jersey, the NJBPU has approved certain rate recovery mechanisms in connection with ACE’s IIP, which ACE has proposed to extend and expand. There can be no assurance that this proposal or any other attempts by ACE to mitigate regulatory lag in its New Jersey base rate cases will be approved, or that even if approved, the rate recovery mechanisms in the IIP or any base rate cases will fully ameliorate the effects of regulatory lag on ACE. Until such time as these proposed mechanisms are approved, if necessary to address the problem of regulatory lag, the utilities would file rate cases at least annually to align their revenue and related cash flow levels with other operation and maintenance spending and capital investments. In future rate cases, Pepco, DPL and ACE, as applicable, would also continue to seek cost recovery and tracking mechanisms from applicable regulatory commissions to reduce the effects of regulatory lag.

Pepco Energy Services

Pepco Energy Services is engaged in the Energy Services business, which is comprised of providing energy efficiency services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power and central energy plants, providing high voltage electric construction and maintenance services to customers throughout the United States, and low voltage electric construction and maintenance services and streetlight construction and asset management services to utilities, municipalities and other customers in the Washington, D.C. metropolitan area.

Pepco Energy Services also owns and operates two oil-fired generation facilities that are scheduled for deactivation in May 2012.

In December 2009, PHI announced the wind down of the retail energy supply component of the Pepco Energy Services business. Pepco Energy Services is implementing this wind down by not entering into any new supply contracts while continuing to perform under its existing supply contracts through their respective expiration dates, the last of which is June 1, 2014. The retail energy supply business has historically generated a substantial portion of the operating revenues and net income of the Pepco Energy Services segment. Operating revenues related to the retail energy supply business for the three months

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ended September 30, 2011 and 2010 were $217 million and $377 million, respectively, while operating income for the same periods was $5 million and $15 million, respectively. Operating revenues related to the retail energy supply business for the nine months ended September 30, 2011 and 2010 were $753 million and $1,275 million, respectively, while operating income for the same periods was $21 million and $45 million, respectively.

In connection with the operation of the retail energy supply business, Pepco Energy Services provided letters of credit of $1 million and posted net cash collateral of $116 million as of September 30, 2011. These collateral requirements, which are based on existing wholesale energy purchase and sale contracts and current market prices, will decrease as the contracts expire, with the collateral expected to be fully released by June 1, 2014. The Energy Services business will not be affected by the wind down of the retail energy supply business.

PHI expects the retail energy supply business to remain profitable through December 31, 2012, based on its existing contracts and its corresponding portfolio of wholesale purchases, and PHI expects to record only immaterial losses beyond that date. Substantially all of Pepco Energy Services’ retail customer obligations will be fully performed by June 1, 2014.

Other Non-Regulated

Through its subsidiary Potomac Capital Investment Corporation, PHI maintains a portfolio of cross-border energy lease investments with a book value at September 30, 2011 of approximately $1.3 billion. In June 2011, Potomac Capital Investment Corporation and its subsidiaries (PCI) completed the early termination of all of the leases comprising one lease investment and a small portion of the leases comprising another lease investment. PCI received $161 million in net cash proceeds and recorded an after-tax gain of $3 million from these early terminations. For a discussion of PHI’s cross-border energy lease investments, see Note (7), “Leasing Activities” and Note (15), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments,” to the Consolidated Financial Statements of PHI set forth in Part I, Item 1 of this Form 10-Q.

Discontinued Operations

In 2010, the Board of Directors of Pepco Holdings approved a plan for the disposition of Conectiv Energy Holding Company. The plan consisted of the sale of the wholesale power generation business, which was completed on July 1, 2010, and the liquidation of all of Conectiv Energy’s remaining assets and businesses, which has been substantially completed. As a result of the plan of disposition, Conectiv Energy’s results of operations for the 2011 and 2010 quarterly and year-to-date periods are reported as discontinued operations. Accordingly, in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, all references to continuing operations exclude the operations of the former Conectiv Energy segment.

Earnings Overview

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

PHI’s net income from continuing operations for the three months ended September 30, 2011 was $80 million, or $0.35 per share, compared to $21 million, or $0.09 per share, for the three months ended September 30, 2010.

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Net income from continuing operations for the three months ended September 30, 2010, included the charges set forth below in the business segments noted which are presented net of federal and state income taxes (assuming a composite tax rate of approximately 40%) and are in millions of dollars:

Debt extinguishment costs including treasury lock hedge (Corporate and Other)	$	81
Restructuring charge (All segments)	$	8
Effects of Pepco divestiture-related claims (Power Delivery)	$	6

Excluding these items, net income from continuing operations would have been $116 million, or $0.52 per share, for the three months ended September 30, 2010. PHI discloses net income from continuing operations and related per share data excluding these items because management believes that these items are not representative of PHI’s ongoing business operations. Management uses this information, and believes that such information is useful to investors, in evaluating PHI’s period-over-period performance. The inclusion of this disclosure is intended to complement, and should not be considered as an alternative to, PHI’s reported net income from continuing operations and related per share data in accordance with accounting principles generally accepted in the United States (GAAP).

PHI’s net loss from discontinued operations for the three months ended September 30, 2011 was less than $1 million, or less than one cent per share, compared to a net loss of $4 million, or $0.01 per share, for the three months ended September 30, 2010.

PHI’s net income (loss) for the three months ended September 30, 2011 and 2010, by operating segment, is set forth in the table below (in millions of dollars):

	2011		2010			Change
Power Delivery	$	66	$	76		$	(10	)
Pepco Energy Services		8		8			—
Other Non-Regulated		5		9			(4	)
Corporate and Other		1		(72	)		73
Net Income from Continuing Operations		80		21			59
Discontinued Operations		—		(4	)		4
Total PHI Net Income	$	80	$	17		$	63

Discussion of Operating Segment Net Income Variances:

Power Delivery’s $10 million decrease in earnings was primarily due to the following:

• $23 million decrease due to higher operating and maintenance expenses primarily from increased system preventative maintenance and reliability activities.

• $3 million decrease due to lower distribution sales, primarily from cooler weather during the 2011 summer months.

• $3 million decrease associated with ACE BGS primarily attributable to a decrease in unbilled revenue.

• $8 million increase due to a restructuring charge recorded in 2010.

• $6 million increase due to an order by the District of Columbia Public Service Commission (DCPSC) in 2010 associated with the effects of Pepco divestiture-related claims.

• $5 million increase associated with higher Default Electricity Supply margins, primarily resulting from an approval by the DCPSC of an increase in Pepco’s cost recovery rate for providing SOS in the District of Columbia, and an adjustment to DPL’s operating and maintenance expense for providing SOS in Delaware.

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• $2 million increase from higher distribution revenue primarily due to Regulated T&D Electric distribution rate increases.

• $2 million increase from higher transmission revenue primarily due to higher rates effective June 1, 2011 related to an increase in transmission plant investment.

Pepco Energy Services’ earnings were unchanged in the two periods; higher operating income from the energy services business and lower credit-related costs offset mark-to-market losses on derivative contracts and lower earnings as a result of the ongoing wind-down of the retail energy supply business.

Other Non-Regulated’s $4 million decrease in earnings was primarily due to lower financial investment portfolio activity, partially offset by favorable income tax adjustments (as further discussed in Note (7), “Leasing Activities – Investment in Finance Leases Held in Trust” and Note (10), “Income Taxes”).

Corporate and Other’s $73 million increase in earnings was primarily due to the unfavorable impact of debt extinguishment costs in 2010 and lower interest expense in 2011 as a result of the reduction in outstanding debt due to the retirement of debt with the Conectiv Energy sale proceeds, partially offset by favorable income tax adjustments in 2010 from the release of certain deferred tax valuation allowances related to state net operating losses.

The $4 million decrease in the net loss from discontinued operations for the three months ended September 30, 2011 as compared to September 30, 2010 was primarily due to losses recorded in 2010 associated with the disposition of Conectiv Energy.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

PHI’s net income from continuing operations for the nine months ended September 30, 2011 was $237 million, or $1.05 per share, compared to $125 million, or $0.56 per share, for the nine months ended September 30, 2010.

Net income from continuing operations for the nine months ended September 30, 2010, included the charges set forth below in the business segments noted, which are presented net of federal and state income taxes (assuming a composite tax rate of approximately 40%) and are in millions of dollars:

Debt extinguishment costs including treasury lock hedge (Corporate and Other)	$	81
Restructuring charge (All segments)	$	8
Effects of Pepco divestiture-related claims (Power Delivery)	$	6

Excluding these items, net income from continuing operations would have been $220 million, or $0.99 per share, for the nine months ended September 30, 2010. PHI discloses net income from continuing operations and related per share data excluding these items because management believes that these items are not representative of PHI’s ongoing business operations. Management uses this information, and believes that such information is useful to investors, in evaluating PHI’s period-over-period performance. The inclusion of this disclosure is intended to complement, and should not be considered as an alternative to, PHI’s reported net income from continuing operations and related per share data in accordance with GAAP.

PHI’s net income from discontinued operations for the nine months ended September 30, 2011 was $1 million, or less than one cent per share, compared to a net loss of $126 million, or $0.56 per share, for the nine months ended September 30, 2010.

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PHI’s net income (loss) for the nine months ended September 30, 2011 and 2010, by operating segment, is set forth in the table below (in millions of dollars):

	2011			2010			Change
Power Delivery	$	185		$	161		$	24
Pepco Energy Services		26			31			(5	)
Other Non-Regulated		30			19			11
Corporate and Other		(4	)		(86	)		82
Net Income from Continuing Operations		237			125			112
Discontinued Operations		1			(126	)		127
Total PHI Net Income (Loss)	$	238		$	(1	)	$	239

Discussion of Operating Segment Net Income Variances:

Power Delivery’s $24 million increase in earnings was primarily due to the following:

• $21 million increase primarily due to an audit settlement with the Internal Revenue Service (IRS) for tax years 1996 through 2002 and a reallocation of deposits with the IRS with respect to tax liabilities in the settlement years and subsequent years, and unfavorable income tax adjustments in 2010 related to interest on uncertain and effectively settled tax positions.

• $20 million increase from higher distribution revenue primarily due to Regulated T&D Electric and Regulated Gas distribution rate increases.

• $15 million increase associated with higher Default Electricity Supply margins, primarily resulting from an approval by the DCPSC of an increase in Pepco’s cost recovery rate for providing SOS in the District of Columbia, and an adjustment to DPL’s operating and maintenance expense for providing SOS in Delaware.

• $13 million increase from higher transmission revenue primarily attributable to higher rates effective June 1, 2010 and 2011, related to increases in transmission plant investment.

• $8 million increase due to a restructuring charge recorded in 2010.

• $6 million increase due to an order by the DCPSC in 2010 associated with the effects of Pepco divestiture-related claims.

• $50 million decrease due to higher operating and maintenance expenses primarily from increased system preventative maintenance and reliability activities.

• $6 million decrease associated with ACE BGS primarily attributable to a decrease in unbilled revenue.

Pepco Energy Services’ $5 million decrease in earnings was primarily due to lower capacity revenues from the generating facilities, mark-to-market losses on derivative contracts, and lower earnings as a result of the ongoing wind-down of the retail energy supply business, partially offset by higher operating income from the energy services business and lower credit-related costs.

Other Non-Regulated’s $11 million increase in earnings was primarily due to favorable income tax adjustments and the gain on the early termination of certain cross-border energy leases, partially offset by lower financial investment portfolio activity (as further discussed in Note (7), “Leasing Activities—Investment in Finance Leases Held in Trust” and Note (10), “Income Taxes”).

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Corporate and Other’s $82 million increase in earnings was primarily due to the unfavorable impact of debt extinguishment costs in 2010 and lower interest expense in 2011 as a result of the reduction in outstanding debt due to the retirement of debt with the Conectiv Energy sale proceeds, partially offset by favorable income tax adjustments in 2010 from the release of certain deferred tax valuation allowances related to state net operating losses.

The $127 million decrease in the net loss from discontinued operations for the nine months ended September 30, 2011 as compared to September 30, 2010 was primarily due to the 2010 write-down associated with the anticipated sale of the wholesale power generation business to Calpine and unrealized losses on derivative instruments no longer qualifying for cash flow hedge accounting, partially offset by gains in the 2010 period from sales of load service supply contracts.

Consolidated Results of Operations

The following results of operations discussion is for the three months ended September 30, 2011, compared to the three months ended September 30, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Continuing Operations

Operating Revenue

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

	2011			2010			Change
Power Delivery	$	1,329		$	1,600		$	(271	)
Pepco Energy Services		312			457			(145	)
Other Non-Regulated		7			15			(8	)
Corporate and Other		(5	)		(5	)		—
Total Operating Revenue	$	1,643		$	2,067		$	(424	)

Power Delivery Business

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

	2011		2010		Change
Regulated T&D Electric Revenue	$	549	$	567	$	(18	)
Default Electricity Supply Revenue		735		979		(244	)
Other Electric Revenue		17		19		(2	)
Total Electric Operating Revenue		1,301		1,565		(264	)
Regulated Gas Revenue		17		16		1
Other Gas Revenue		11		19		(8	)
Total Gas Operating Revenue		28		35		(7	)
Total Power Delivery Operating Revenue	$	1,329	$	1,600	$	(271	)

Regulated Transmission and Distribution (T&D) Electric Revenue includes revenue from the distribution of electricity, including the distribution 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 at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

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Default Electricity Supply Revenue is the revenue received from the supply of electricity by PHI’s utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier. Depending on the jurisdiction, Default Electricity Supply is also known as SOS or BGS. The costs related to Default Electricity Supply are included in “Fuel and Purchased Energy.” Default Electricity Supply Revenue also includes revenue from Transition Bond Charges that ACE receives, and pays to Atlantic City Electric Transition Funding LLC (ACE Funding), to fund the principal and interest payments on bonds issued by ACE Funding (Transition Bonds) and revenue in the form of transmission enhancement credits that PHI utility subsidiaries receive as transmission owners from PJM for approved regional transmission expansion plan costs (Transmission Enhancement Credits).

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally 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 includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates.

Other Gas Revenue consists of DPL’s off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

Regulated T&D Electric

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	217	$	231	$	(14	)
Commercial and industrial		251		261		(10	)
Other		81		75		6
Total Regulated T&D Electric Revenue	$	549	$	567	$	(18	)

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

	2011		2010		Change
Regulated T&D Electric Sales (Gigawatt hours (GWh))
Residential		5,584		5,871		(287	)
Commercial and industrial		8,687		8,887		(200	)
Other		58		58		—
Total Regulated T&D Electric Sales		14,329		14,816		(487	)

	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		1,634		1,631		3
Commercial and industrial		198		198		—
Other		2		2		—
Total Regulated T&D Electric Customers		1,834		1,831		3

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The Pepco, DPL and ACE service territories are located within a corridor extending from the District of Columbia 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 chemical, glass, pharmaceutical, steel manufacturing, food processing, and oil refining.

Regulated T&D Electric Revenue decreased by $18 million primarily due to:

• A decrease of $11 million due to an ACE New Jersey Societal Benefit Charge rate decrease that became effective in January 2011 (which is offset in Deferred Electric Service Costs).

• A decrease of $8 million due to lower pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of rate decreases in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the county.

• A decrease of $4 million due to non-weather related average customer usage.

• A decrease of $3 million due to lower sales as a result of cooler weather during the 2011 summer months as compared to 2010.

The aggregate amount of these decreases was partially offset by:

• An increase of $6 million in transmission revenue primarily attributable to higher rates effective June 1, 2011 related to an increase in transmission plant investment.

• An increase of $4 million due to distribution rate increases (DPL in Maryland effective July 2011, and in Delaware effective February 2011).

Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	518	$	705	$	(187	)
Commercial and industrial		175		214		(39	)
Other		42		60		(18	)
Total Default Electricity Supply Revenue	$	735	$	979	$	(244	)

Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale by ACE in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated non-utility generators (NUGs), and (ii) revenue from Transmission Enhancement Credits.

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	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		4,869		5,553		(684	)
Commercial and industrial		1,700		1,988		(288	)
Other		17		20		(3	)
Total Default Electricity Supply Sales		6,586		7,561		(975	)

	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		1,451		1,554		(103	)
Commercial and industrial		139		152		(13	)
Other		1		2		(1	)
Total Default Electricity Supply Customers		1,591		1,708		(117	)

Default Electricity Supply Revenue decreased by $244 million primarily due to:

• A decrease of $109 million as a result of lower Default Electricity Supply rates.

• A decrease of $75 million due to lower sales, primarily as a result of residential and commercial customer migration to competitive suppliers.

• A decrease of $35 million due to lower sales as a result of cooler weather during the 2011 summer months as compared to 2010.

• A decrease of $17 million in wholesale energy and capacity resale revenues primarily due to the sale of lower volumes of electricity and capacity purchased from NUGs.

• A decrease of $6 million due to lower non-weather related average customer usage.

The decrease in total Default Electricity Supply Revenue includes a decrease of $6 million in unbilled revenue attributable to ACE’s BGS. Under the BGS terms approved by the New Jersey Board of Public Utilities, ACE is entitled to recover from its customers all of its costs of providing BGS. If the costs of providing BGS exceed the BGS revenue, the excess costs are deferred in Deferred Electric Service Costs. ACE’s BGS unbilled revenue is not included in the deferral calculation, and therefore has an impact on the results of operations in the period during which it is accrued. While the change in the amount of unbilled revenue from year to year typically is not significant, for the three months ended September 30, 2011, BGS unbilled revenue decreased by $6 million as compared to the three months ended September 30, 2010, which resulted in a $4 million decrease in PHI’s net income. The decrease was primarily due to lower Default Electricity Supply rates during the unbilled revenue period at the end of the three months ended September 30, 2011, as compared to the corresponding period in 2010.

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Regulated Gas

	2011		2010		Change
Regulated Gas Revenue
Residential	$	9	$	9	$	—
Commercial and industrial		6		6		—
Transportation and other		2		1		1
Total Regulated Gas Revenue	$	17	$	16	$	1
	2011		2010		Change
Regulated Gas Sales (billion cubic feet)
Residential		1		—		1
Commercial and industrial		—		—		—
Transportation and other		1		2		(1	)
Total Regulated Gas Sales		2		2		—
	2011		2010		Change
Regulated Gas Customers (in thousands)
Residential		114		113		1
Commercial and industrial		9		10		(1	)
Transportation and other		—		—		—
Total Regulated Gas Customers		123		123		—

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 chemical and pharmaceutical.

Regulated Gas Revenue increased by $1 million primarily due to an increase of $2 million due to higher sales as a result of colder weather during September 2011 as compared to September 2010. The increase was partially offset by a decrease of $1 million due to lower non-weather related average customer usage.

Other Gas Revenue

Other Gas Revenue decreased by $8 million primarily due to lower volumes of off-system sales to electric generators and gas marketers.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased $145 million primarily due to a decrease of $159 million due to lower retail supply sales volume, which was primarily attributable to the ongoing wind down of the retail energy supply business. The decrease was partially offset by:

• An increase of $11 million due to increased energy services activities.

• An increase of $4 million due to higher generation revenues partially offset by lower capacity revenues at the generating facilities.

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Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

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

	2011		2010			Change
Power Delivery	$	710	$	948		$	(238	)
Pepco Energy Services		275		410			(135	)
Corporate and Other		—		(1	)		1
Total	$	985	$	1,357		$	(372	)

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy consists of the cost of electricity and natural gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of natural gas purchased for off-system sales. Fuel and Purchased Energy expense decreased by $238 million primarily due to:

• A decrease of $99 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $88 million primarily due to customer migration to competitive suppliers.

• A decrease of $27 million due to lower electricity sales primarily as a result of cooler weather during the 2011 summer months as compared to 2010.

• A decrease of $15 million in deferred electricity expense primarily due to lower Default Electricity Supply rates, which resulted in a lower rate of recovery of Default Electricity Supply costs.

• A decrease of $5 million in the cost of gas purchases for off-system sales as a result of lower volumes purchased.

• A decrease of $4 million from the settlement of financial hedges entered into as part of DPL’s hedge program for regulated natural gas.

Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $135 million primarily due to:

• A decrease of $105 million resulting from lower volumes of electricity purchased to serve decreased retail electricity sales volume as a result of the ongoing wind down of the retail energy supply business.

• A decrease of $41 million resulting from lower volumes of natural gas purchased to serve decreased retail natural gas volumes as a result of the ongoing wind down of the retail energy supply business.

The aggregate amount of these decreases was partially offset by:

• An increase of $7 million due to higher fuel usage associated with the generating facilities.

• An increase of $5 million due to increased energy services activities.

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Other Operation and Maintenance

A detail of PHI’s Other Operation and Maintenance expense is as follows:

	2011			2010			Change
Power Delivery	$	243		$	210		$	33
Pepco Energy Services		21			26			(5	)
Corporate and Other		(25	)		(8	)		(17	)
Total	$	239		$	228		$	11

Other Operation and Maintenance expense for Power Delivery increased by $33 million primarily due to:

• An increase of $11 million primarily due to higher preventative maintenance and tree trimming costs.

• An increase of $6 million primarily due to a 2010 adjustment for February 2010 severe winter storm costs incurred by Pepco that previously were charged to Other Operation and Maintenance expense. The adjustment was recorded in accordance with an MPSC rate order issued in August 2010, allowing for the recovery of the costs.

• An increase of $5 million in employee-related costs primarily due to higher pension and other postretirement benefit expenses.

• An increase of $5 million in customer support and communication costs.

• An increase of $3 million in legal services, primarily outside counsel fees.

• An increase of $2 million in emergency restoration costs. The increase is primarily related to the significant incremental costs incurred for repair work following Hurricane Irene in August 2011. Costs incurred for repair work were $30 million, of which $24 million was deferred as a regulatory asset to reflect the probable recovery of these storm costs in certain jurisdictions, and the remaining $6 million was charged to Other operation and maintenance expense. A large portion of the costs of the restoration work associated with Hurricane Irene relates to services provided by outside contractors and other utilities and invoices for such services in most instances have not yet been received and have been estimated. Actual invoices may vary from these estimates.

The aggregate amount of these increases was partially offset by a decrease of $3 million, associated with certain adjustments recorded by PHI in the third quarter of 2011 associated with the accounting for DPL and Pepco Default Electricity Supply. These adjustments were primarily due to the under-recognition of allowed returns on administrative costs.

Restructuring Charge

As a result of PHI’s organizational review in the second quarter of 2010, PHI’s operating expenses include a pre-tax restructuring charge of $14 million for the three months ended September 30, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

Depreciation and Amortization

Depreciation and Amortization expense increased by $11 million to $115 million in 2011 from $104 million in 2010 primarily due to:

• An increase of $8 million in amortization of stranded costs as the result of higher revenue due to rate increases effective October 2010 for the ACE Transition Bond Charge and the Market Transition Charge Tax (partially offset in Default Electricity Supply Revenue).

• An increase of $4 million due to utility plant additions.

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Other Taxes

Other Taxes decreased by $4 million to $126 million in 2011 from $130 million in 2010. The decrease was primarily due to $8 million in lower pass-throughs (substantially offset by a corresponding decrease in Regulated T&D Electric Revenue) primarily resulting from rate decreases in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco. The decrease was partially offset by an increase of $5 million due to an adjustment recorded by Pepco in the third quarter of 2010 to correct certain errors related to other taxes.

Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, represent (i) the over or under recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the over or under recovery of New Jersey Societal Benefit Program costs incurred by ACE. The cost of electricity purchased is reported under Fuel and Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of New Jersey Societal Benefit Programs is reported under Other Operation and Maintenance and the corresponding revenue is reported under Regulated T&D Electric Revenue.

Deferred Electric Service Costs decreased by $30 million, to an expense reduction of $17 million in 2011 as compared to an expense of $13 million in 2010, primarily due to a decrease in deferred electricity expense as a result of lower Default Electricity Supply rates, partially offset by lower electricity supply costs.

Effects of Pepco Divestiture-Related Claims

PHI’s operating expenses include a pre-tax expense of $9 million for the three months ended September 30, 2010 related to a DCPSC order that disallowed certain items that Pepco had included in the costs it deducted in calculating the net proceeds from the sale of its generation-related assets in 2000.

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $137 million primarily due to the loss on extinguishment of debt that was recorded during the third quarter of 2010 and lower interest expense in 2011 resulting from the reduction in outstanding long-term debt due to the retirement of debt in 2010 with the proceeds from the Conectiv Energy sale.

Loss on Extinguishment of Debt

During the three months ended September 30, 2010, PHI recorded a loss on extinguishment of debt of $135 million that was comprised of a $120 million pre-tax loss pursuant to a cash tender offer for Senior Notes made during the quarter and a $15 million pre-tax loss due to the reclassification of treasury rate lock losses from Accumulated Other Comprehensive Loss to income as a result of the extinguishment of the debt related to the treasury rate locks.

Income Tax Expense

PHI’s consolidated effective tax rates from continuing operations for the three months ended September 30, 2011 and 2010 were 40.7% and (40.0)%, respectively. The increase in the effective tax rate was primarily due to the non-recurring benefit recorded in the third quarter of 2010 related to the 2010 corporate restructuring that impacted state tax expense and state deferred tax balances, the benefit of certain deferred tax basis adjustments recorded in 2010 and changes in estimates and interest related to uncertain and effectively settled tax positions.

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In addition, as discussed further in Note (15), “Commitments and Contingencies— District of Columbia Tax Legislation,” the Fiscal Year 2012 Budget Support Act of 2011 (the Budget Support Act) became law during the third quarter of 2011. The Budget Support Act includes a provision that requires corporate taxpayers in the District of Columbia (the District) to calculate taxable income allocable or apportioned to the District by reference to the income and apportionment factors applicable to commonly controlled entities organized within the United States that are engaged in a unitary business. Previously, only the income of companies with direct nexus to the District was taxed. As a result of the change, during the third quarter of 2011, PHI recorded an additional state income tax expense of $2 million.

The deferred tax basis adjustments recorded in 2010 were the result of a $2 million adjustment to eliminate deferred tax liabilities associated with a goodwill impairment charge recorded in 2005, and the recording of a $2 million benefit related to deferred tax attributes.

The following results of operations discussion is for the nine months ended September 30, 2011, compared to the nine months ended September 30, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Continuing Operations

Operating Revenue

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

	2011			2010			Change
Power Delivery	$	3,671		$	4,011		$	(340	)
Pepco Energy Services		993			1,480			(487	)
Other Non-Regulated		35			41			(6	)
Corporate and Other		(13	)		(10	)		(3	)
Total Operating Revenue	$	4,686		$	5,522		$	(836	)

Power Delivery Business

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

	2011		2010		Change
Regulated T&D Electric Revenue	$	1,456	$	1,413	$	43
Default Electricity Supply Revenue		1,996		2,380		(384	)
Other Electric Revenue		50		52		(2	)
Total Electric Operating Revenue		3,502		3,845		(343	)
Regulated Gas Revenue.		134		127		7
Other Gas Revenue		35		39		(4	)
Total Gas Operating Revenue		169		166		3
Total Power Delivery Operating Revenue	$	3,671	$	4,011	$	(340	)

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Regulated T&D Electric

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	539	$	529	$	10
Commercial and industrial		676		668		8
Other		241		216		25
Total Regulated T&D Electric Revenue	$	1,456	$	1,413	$	43

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

	2011		2010		Change
Regulated T&D Electric Sales (GWh)
Residential		14,214		14,521		(307	)
Commercial and industrial		23,905		24,315		(410	)
Other		181		182		(1	)
Total Regulated T&D Electric Sales		38,300		39,018		(718	)

	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		1,634		1,631		3
Commercial and industrial		198		198		—
Other		2		2		—
Total Regulated T&D Electric Customers		1,834		1,831		3

Regulated T&D Electric Revenue increased by $43 million primarily due to:

• An increase of $32 million due to distribution rate increases (Pepco in the District of Columbia effective March 2010 and July 2010, and in Maryland effective July 2010; DPL in Maryland effective July 2011, and in Delaware effective April 2010 and February 2011; and ACE in New Jersey effective June 2010).

• An increase of $25 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 and June 1, 2011 related to increases in transmission plant investment.

• An increase of $16 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily resulting from rate increases in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the county.

• An increase of $4 million due to Pepco customer growth of 1% in 2011, primarily in the residential class.

The aggregate amount of these increases was partially offset by:

• A decrease of $24 million due to an ACE New Jersey Societal Benefit Charge rate decrease that became effective in January 2011 (which is offset in Deferred Electric Service Costs).

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• A decrease of $6 million due to lower sales as a result of cooler weather during the 2011 spring and summer months as compared to 2010.

Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	1,363	$	1,644	$	(281	)
Commercial and industrial		508		581		(73	)
Other		125		155		(30	)
Total Default Electricity Supply Revenue	$	1,996	$	2,380	$	(384	)

Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale by ACE in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated NUGs, and (ii) revenue from Transmission Enhancement Credits.

	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		12,568		13,819		(1,251	)
Commercial and industrial		4,753		5,492		(739	)
Other		54		68		(14	)
Total Default Electricity Supply Sales		17,375		19,379		(2,004	)

	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		1,451		1,554		(103	)
Commercial and industrial		139		152		(13	)
Other		1		2		(1	)
Total Default Electricity Supply Customers		1,591		1,708		(117	)

Default Electricity Supply Revenue decreased by $384 million primarily due to:

• A decrease of $174 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

• A net decrease of $135 million as a result of lower Pepco and DPL Default Electricity Supply rates, partially offset by higher ACE rates.

• A decrease of $66 million due to lower sales as a result of cooler weather during the 2011 spring and summer months as compared to 2010.

• A decrease of $24 million in wholesale energy and capacity resale revenues primarily due to the sale of lower volumes of electricity and capacity purchased from NUGs.

• A decrease of $3 million due to a decrease in revenue from Transmission Enhancement Credits.

The aggregate amount of these decreases was partially offset by:

• An increase of $15 million due to higher non-weather related average customer usage.

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• An increase of $3 million resulting from an approval by the DCPSC of an increase in Pepco’s cost recovery rate for providing Default Electricity Supply in the District of Columbia to provide for recovery of higher cash working capital costs incurred in prior periods. The higher cash working capital costs were incurred when the billing cycle for Default Electricity suppliers was shortened from a monthly to a weekly period, effective in June 2009.

The decrease in total Default Electricity Supply Revenue includes a decrease of $12 million in unbilled revenue attributable to ACE’s BGS. Under the BGS terms approved by the New Jersey Board of Public Utilities, ACE is entitled to recover from its customers all of its costs of providing BGS. If the costs of providing BGS exceed the BGS revenue, the excess costs are deferred in Deferred Electric Service Costs. ACE’s BGS unbilled revenue is not included in the deferral calculation, and therefore has an impact on the results of operations in the period during which it is accrued. While the change in the amount of unbilled revenue from year to year typically is not significant, for the nine months ended September 30, 2011, BGS unbilled revenue decreased by $12 million as compared to the nine months ended September 30, 2010, which resulted in a $7 million decrease in PHI’s net income. The decrease was primarily due to lower Default Electricity Supply rates and lower customer usage during the unbilled revenue period at the end of the nine months ended September 30, 2011, as compared to the corresponding period in 2010.

Regulated Gas

	2011		2010		Change
Regulated Gas Revenue
Residential	$	82	$	78	$	4
Commercial and industrial		45		44		1
Transportation and other		7		5		2
Total Regulated Gas Revenue	$	134	$	127	$	7
	2011		2010		Change
Regulated Gas Sales (billion cubic feet)
Residential		6		5		1
Commercial and industrial		3		3		—
Transportation and other		5		5		—
Total Regulated Gas Sales		14		13		1
	2011		2010		Change
Regulated Gas Customers (in thousands)
Residential		114		113		1
Commercial and industrial		9		10		(1	)
Transportation and other		—		—		—
Total Regulated Gas Customers		123		123		—

Regulated Gas Revenue increased by $7 million primarily due to:

• An increase of $18 million due to higher sales primarily as a result of colder weather during the 2011 winter months as compared to 2010.

�� An increase of $2 million due to a distribution rate increase effective February 2011.

The aggregate amount of these increases was partially offset by a decrease of $13 million due to lower non-weather related average customer usage.

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Other Gas Revenue

Other Gas Revenue decreased by $4 million primarily due to lower volumes of off-system sales to electric generators and gas marketers.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased by $487 million primarily due to:

• A decrease of $516 million resulting from lower retail supply sales volume primarily attributable to the ongoing wind down of the retail energy supply business.

• A decrease of $29 million resulting from lower generation and capacity revenues at the generating facilities.

The aggregate amount of these decreases was partially offset by an increase of $57 million due to increased energy services activities.

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:

	2011		2010			Change
Power Delivery	$	2,000	$	2,453		$	(453	)
Pepco Energy Services		875		1,333			(458	)
Corporate and Other		—		(5	)		5
Total	$	2,875	$	3,781		$	(906	)

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy consists of the cost of electricity and natural gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of natural gas purchased for off-system sales. Fuel and Purchased Energy expense decreased by $453 million primarily due to:

• A decrease of $221 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $173 million primarily due to customer migration to competitive suppliers.

• A decrease of $54 million due to lower electricity sales primarily as a result of cooler weather during the 2011 spring and summer months as compared to 2010.

• A decrease of $10 million in the cost of gas purchases for on-system sales as a result of lower average gas prices and lower withdrawals from storage.

• A decrease of $8 million from the settlement of financial hedges entered into as part of DPL’s hedge program for regulated natural gas.

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The aggregate amount of these decreases was partially offset by an increase of $18 million in deferred natural gas expense as a result of a higher rate of recovery of natural gas supply costs.

Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $458 million primarily due to:

• A decrease of $354 million associated with lower volumes of electricity purchased to serve decreased retail electricity sales volume as a result of the ongoing wind down of the retail energy supply business.

• A decrease of $137 million attributable to lower volumes of natural gas purchased to serve decreased retail natural gas volumes as a result of the ongoing wind down of the retail energy supply business.

• A decrease of $10 million due to lower fuel usage associated with the generating facilities.

The aggregate amount of these decreases was partially offset by an increase of $43 million due to increased energy services activities.

Other Operation and Maintenance

A detail of PHI’s Other Operation and Maintenance expense is as follows:

	2011			2010			Change
Power Delivery	$	662		$	590		$	72
Pepco Energy Services		63			67			(4	)
Other Non-Regulated		3			2			1
Corporate and Other		(46	)		(23	)		(23	)
Total	$	682		$	636		$	46

Other Operation and Maintenance expense for Power Delivery increased by $72 million; however, excluding an increase of $4 million primarily related to New Jersey Societal Benefit Program costs that are deferred and recoverable, Other Operation and Maintenance expense increased by $68 million. The $68 million increase was primarily due to:

• An increase of $38 million primarily due to higher tree trimming and preventative maintenance costs.

• An increase of $10 million primarily due to 2010 Pepco adjustments for (i) February 2010 severe winter storm costs of $5 million and (ii) distribution rate case costs of $4 million that previously were charged to other operation and maintenance expense. The adjustments were recorded in accordance with an MPSC rate order issued in August 2010 and a DCPSC rate order issued in February 2010 allowing for the recovery of the costs.

• An increase of $10 million in customer support and communication costs.

• An increase of $5 million primarily due to PHI’s emergency restoration improvement project and reliability improvement costs.

• An increase of $4 million in emergency restoration costs. The increase is primarily related to the significant incremental costs incurred for repair work following Hurricane Irene in August 2011. Costs incurred for repair work were $30 million, of which $24 million was deferred as a regulatory asset to reflect the probable recovery of these storm costs in certain jurisdictions, and the remaining $6 million was

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charged to Other operation and maintenance expense. A large portion of the costs of the restoration work associated with Hurricane Irene relates to services provided by outside contractors and other utilities and invoices for such services in most instances have not yet been received and have been estimated. Actual invoices may vary from these estimates.

• An increase of $4 million in employee-related costs, primarily benefit expenses.

• An increase of $4 million in legal services, primarily outside counsel fees.

The aggregate amount of these increases was partially offset by:

• A decrease of $11 million associated with $8 million and $3 million adjustments recorded by PHI in the second and third quarter of 2011, respectively, associated with the accounting for DPL and Pepco Default Electricity Supply. These adjustments were primarily due to the under-recognition of allowed returns on working capital and administrative costs.

• A decrease of $4 million due to the 2010 accrual of environmental remediation costs related to a 1999 oil release at the Indian River generating facility then owned by DPL, as further discussed under “Indian River Oil Release” in Note (15), “Commitments and Contingencies” to the consolidated financial statements of PHI.

Restructuring Charge

As a result of PHI’s organizational review in the second quarter of 2010, PHI’s operating expenses include a pre-tax restructuring charge of $14 million for the nine months ended September 30, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

Depreciation and Amortization

Depreciation and Amortization expense increased by $39 million to $325 million in 2011, from $286 million in 2010 primarily due to:

• An increase of $21 million in amortization of stranded costs as the result of higher revenue due to rate increases effective October 2010 for the ACE Transition Bond Charge and the Market Transition Charge Tax (partially offset in Default Electricity Supply Revenue).

• An increase of $11 million due to utility plant additions.

• An increase of $4 million in amortization of regulatory assets primarily associated with the EmPower Maryland (a demand-side management program) surcharge that became effective in March 2010 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

• An increase of $1 million in amortization of software upgrades to Pepco’s Energy Management System.

Other Taxes

Other Taxes increased by $19 million to $346 million in 2011 from $327 million in 2010. The increase primarily resulted from:

• An increase of $14 million primarily due to rate increases in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

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• An increase of $5 million due to an adjustment recorded by Pepco in the third quarter of 2010 to correct certain errors related to other taxes.

Gain on Early Termination of Finance Leases Held in Trust

PHI’s operating expenses include a $39 million pre-tax gain for the nine months ended September 30, 2011 associated with the early termination of several leases included in its cross-border energy lease portfolio.

Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, represent (i) the over or under recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the over or under recovery of New Jersey Societal Benefit Program costs incurred by ACE. The cost of electricity purchased is reported under Fuel and Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of New Jersey Societal Benefit Programs is reported under Other Operation and Maintenance and the corresponding revenue is reported under Regulated T&D Electric Revenue.

Deferred Electric Service Costs increased by $20 million, to an expense reduction of $49 million in 2011 as compared to an expense reduction of $69 million in 2010, primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply rates and lower electricity supply costs.

Effects of Pepco Divestiture-Related Claims

PHI’s operating expenses include a pre-tax expense of $11 million for the nine months ended September 30, 2010 related to a DCPSC order that disallowed certain items that Pepco had included in the costs it deducted in calculating the net proceeds from the sale of its generation-related assets in 2000.

Other Income (Expenses)

Other expenses (which are net of Other Income) decreased by $193 million primarily due to the loss on extinguishment of debt that was recorded during the third quarter of 2010 and lower interest expense in 2011 resulting from the reduction in outstanding long-term debt due to the retirement of debt in 2010 with the proceeds from the Conectiv Energy sale.

Loss on Extinguishment of Debt

During the nine months ended September 30, 2010, PHI recorded a loss on extinguishment of debt of $135 million that was comprised of a $120 million pre-tax loss pursuant to a cash tender offer for Senior Notes made during the quarter and a $15 million pre-tax loss due to the reclassification of treasury rate lock losses from Accumulated Other Comprehensive Loss to income as a result of the extinguishment of the debt related to the treasury rate locks.

Income Tax Expense

PHI’s consolidated effective tax rates from continuing operations for the nine months ended September 30, 2011 and 2010 were 37.6% and 29.4%, respectively. The increase in the effective tax rate was primarily due to the impact of the early termination of certain cross border energy leases and the non-recurring benefit of the 2010 corporate restructuring affecting state tax benefits and state deferred tax balances recorded in the third quarter of 2010. This increase was partially offset by interest benefits associated with the settlement with the IRS discussed below.

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As discussed further in Note (7), “Leasing Activities,” during the second quarter of 2011, PHI terminated early its interest in certain cross-border energy leases prior to the end of the stated term. As a result of the early terminations, PHI reversed $22 million of previously recognized Federal income tax benefits associated with those leases which will not be realized.

In the second quarter of 2011, PHI reached a settlement with the IRS with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that had been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, PHI has recorded an additional tax benefit in the amount of $17 million (after-tax). This additional interest income was recorded in the second quarter of 2011.

PHI also recorded additional state tax expense as a result of the District of Columbia’s mandatory unitary combined reporting which became effective during the third quarter 2011.

The 2010 effective tax rate also included the non-recurring impact of the April 2010 corporate restructuring. As a result of this restructuring, PHI recorded approximately $16 million of non-recurring tax benefits in 2010 including approximately $8 million resulting from a change in state apportionment factors and the release of $8 million of valuation allowances on deferred tax assets related to state net operating losses.

PHI also recorded $6 million of additional income tax expense related to erroneously recorded interest income for state tax purposes on uncertain and effectively settled tax positions as further discussed in Note (2), “Significant Accounting Policies—Income Tax Adjustments.”

Discontinued Operations

For the nine months ended September 30, 2011, the $1 million income from discontinued operations, net of income taxes, includes after-tax income of $4 million arising from adjustments to certain accrued expenses for obligations associated with the sale of the wholesale power generation business to Calpine. These adjustments were made to reflect the actual amounts paid to Calpine during the first quarter of 2011. Income from discontinued operations, net of income taxes for the nine months ended September 30, 2011 also includes a $1 million after-tax gain on the sale of a tolling agreement. Offsetting these amounts was an expense of approximately $1 million (after-tax) which was incurred in connection with the financial transaction entered into with a third party on January 6, 2011, under which Conectiv Energy transferred its remaining portfolio of derivatives, including financially settled natural gas and electric power transactions, for all remaining periods from February 1, 2011 forward. In connection with the closing of the transaction, Conectiv paid the third party $82 million, primarily representing the fair value of the derivatives at February 1, 2011, and an after-tax administrative fee of $1 million. No additional material gain or loss was recognized as a result of this transaction as the derivatives were previously marked to fair value through earnings in 2010.

For the nine months ended September 30, 2010, the net loss from discontinued operations, net of income taxes, of $126 million includes income from operations of $2 million for Conectiv Energy, which includes the after-tax effects of employee severance and retention benefits of $9 million and after-tax accruals of certain obligations associated with the anticipated sale of the wholesale power generation business to Calpine of $12 million.

Net losses from dispositions of assets and businesses of discontinued operations, net of income taxes of $128 million for the nine months ended September 30, 2010, includes (i) the after-tax loss on the sale of

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the wholesale power generation business to Calpine of $73 million, (ii) after-tax net losses on sales of assets and businesses not sold to Calpine of $27 million (inclusive of the recognition of after-tax unrealized losses on derivative contracts considered no longer probable to occur of $50 million recorded in the second quarter of 2010), and (iii) tax charges of $28 million for the establishment of valuation allowances against certain deferred tax assets primarily associated with state net operating losses, the remeasurement of deferred taxes for expected changes in state income tax apportionment factors, and the write-off of certain tax credit carryforwards no longer expected to be realized.

Capital Resources and Liquidity

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

Working Capital

At September 30, 2011, Pepco Holdings’ current assets on a consolidated basis totaled $1.6 billion and its consolidated current liabilities totaled $1.7 billion, resulting in a working capital deficit of $65 million. PHI expects the working capital deficit at September 30, 2011 to be funded during 2011 through cash flows from operations and anticipated reductions in collateral requirements due to the ongoing wind down of the Pepco Energy Services retail energy supply business. At December 31, 2010, Pepco Holdings’ current assets on a consolidated basis totaled $1.8 billion and its consolidated current liabilities totaled $1.8 billion, resulting in a working capital deficit of $40 million . The decrease in working capital from December 31, 2010 to September 30, 2011 was due primarily to the decrease in prepayments of income taxes in addition to a decrease in the current portion of Conectiv Energy assets held for sale.

At September 30, 2011, Pepco Holdings’ cash and cash equivalents totaled $103 million, which consisted of cash, uncollected funds, and cash equivalent investments of $86 million. Current restricted cash equivalents (cash that is available to be used only for designated purposes) totaled $17 million. At December 31, 2010, Pepco Holdings’ cash and cash equivalents totaled $21 million, of which $1 million is reflected on the Balance Sheet in Conectiv Energy assets held for sale, and its current restricted cash equivalents totaled $11 million.

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

	As of September 30, 2011
	(millions of dollars)
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	18	$	146
Commercial Paper		399		—		—		—		—		—		399
Total Short-Term Debt	$	399	$	—	$	105	$	23	$	—	$	18	$	545
Current Maturities of Long-Term Debt and Project Funding	$	—	$	—	$	66	$	—	$	37	$	10	$	113

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	As of December 31, 2010
	(millions of dollars)
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	18	$	146
Commercial Paper		230		—		—		158		—		—		388
Total Short-Term Debt	$	230	$	—	$	105	$	181	$	—	$	18	$	534
Current Maturities of Long-Term Debt and Project Funding	$	—	$	—	$	35	$	—	$	35	$	5	$	75

Financing Activity During the Three Months Ended September 30, 2011

In July 2011, ACE Funding made principal payments of $6 million on its Series 2002-1 Bonds, Class A-3, and $2 million on its Series 2003-1 Bonds, Class A-2.

Credit Facilities

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, and to support its commercial paper program. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement with respect to the facility, which among other changes, extends the expiration date of the facility to August 1, 2016.

The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit for PHI is $750 million and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and one month LIBOR plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain sales and dispositions, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The amended and restated credit agreement contains certain covenants and other customary agreements and requirements that, if not

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complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all financial covenants under this facility as of September 30, 2011. There are no rating triggers associated with the credit facility.

Additionally, PHI had two bi-lateral 364-day unsecured credit agreements totaling $200 million as of September 30, 2011 that expired according to their terms on October 26, 2011. Under each of those credit agreements, PHI had access to revolving and floating rate loans over the terms of the agreements. These facilities were established to provide additional liquidity and collateral support for Pepco Energy Services’ retail energy supply business. Based on the progress made toward winding down the retail energy supply business, the level of liquidity and collateral needed to support this business has decreased. As a result, PHI concluded that these credit agreements were no longer needed.

Financing Activities Subsequent to September 30, 2011

In October 2011, ACE Funding made principal payments of $8 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

Cash and Credit Facilities Available as of September 30, 2011

	Consolidated PHI		PHI Parent		Utility Subsidiaries
	(millions of dollars)
Credit Facilities (Total Capacity)	$	1,700	$	950	$	750
Less: Letters of Credit issued		9		4		5
Commercial Paper outstanding		399		399		—
Remaining Credit Facilities Available		1,292		547		745
Cash Invested in Money Market Funds (a)		86		—		86
Total Cash and Credit Facilities Available	$	1,378	$	547	$	831

(a) Cash and cash equivalents reported on the PHI Consolidated Balance Sheet total $103 million, of which $86 million was invested in money market funds and the balance was held in cash and uncollected funds.

At September 30, 2011 and December 31, 2010, the aggregate amount of cash plus unused borrowing capacity under the credit facilities available to meet the combined future liquidity needs of Pepco Energy Services totaled $547 million and $728 million, respectively.

Collateral Requirements of Pepco Energy Services

Pepco Energy Services, in the ordinary course of its retail energy supply business, enters into various contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce its financial exposure to changes in the value of its assets and obligations due to energy price fluctuations. These contracts typically have collateral requirements. Depending on the contract terms, the collateral required to be posted by Pepco Energy Services can be of varying forms, including cash and letters of credit.

During periods of declining energy prices, Pepco Energy Services has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees, (i) assumed, by novation, the electricity purchase obligations of Pepco Energy Services in years 2009 through 2011 under several wholesale purchase

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contracts, and (ii) agreed to supply electricity to Pepco Energy Services on the same terms as the novated transactions, but without imposing on Pepco Energy Services any obligation to post collateral based on changes in electricity prices. The upfront fees incurred by Pepco Energy Services in 2009 in the amount of $25 million are being amortized into expense in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of the novation. For the three months ended September 30, 2011 and 2010, Pepco Energy Services recognized less than $1 million and approximately $1 million, respectively, of the fees in “Interest expense.” For the nine months ended September 30, 2011 and 2010, Pepco Energy Services recognized approximately $1 million and $6 million, respectively, of the fees in “Interest expense.”

As of September 30, 2011, Pepco Energy Services had posted net cash collateral of $116 million and provided letters of credit of $1 million. At December 31, 2010, Pepco Energy Services had posted net cash collateral of $117 million and provided letters of credit of $113 million. Pepco Energy Services’ collateral requirements will continue to decline as its retail energy supply business winds down.

Remaining Collateral Requirements of Conectiv Energy

As of September 30, 2011, all cash collateral related to Conectiv Energy had been returned and there were no outstanding letters of credit. At December 31, 2010, Conectiv Energy had posted net cash collateral of $104 million and there were no outstanding letters of credit.

Pension and Postretirement Benefit Plans

Pension benefits are provided under PHI’s defined benefit pension plan (the PHI Retirement Plan), a non-contributory retirement plan that covers substantially all employees of Pepco, DPL and ACE and certain employees of other PHI subsidiaries. PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level that is at least equal to the funding target as defined under the Pension Protection Act of 2006. The funding target under the Pension Protection Act is an amount that is being phased in over time. The funding target was 96% of the accrued liability for 2010 and is 100% of the accrued liability for 2011.

Under the Pension Protection Act, if a plan incurs a funding shortfall in the preceding plan year, there can be required minimum quarterly contributions in the current and following plan years. PHI satisfied the minimum required contribution rules in 2010. Although PHI currently has no minimum funding requirement under the Pension Protection Act guidelines, Pepco, DPL and ACE in the first quarter of 2011 made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $40 million, $40 million and $30 million, respectively. The $110 million in contributions brought the PHI Retirement Plan assets to the funding target level for 2011 under the Pension Protection Act. During 2010, PHI Service Company made discretionary tax-deductible contributions totaling $100 million to the PHI Retirement Plan, which brought plan assets to the funding target level for 2010 under the Pension Protection Act. Pepco, DPL and ACE did not make contributions to the PHI Retirement Plan in 2010.

Based on the results of the 2010 actuarial valuation, PHI’s net periodic pension and other postretirement benefit costs were approximately $116 million in 2010 and the current estimate of benefit cost for 2011 is approximately $94 million. The utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and other postretirement benefit costs. Approximately 30% of the net periodic pension and other postretirement benefit costs are capitalized. PHI estimates that its net periodic pension and other postretirement benefit expense will be approximately $66 million in 2011, as compared to $81 million in 2010.

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Cash Flow Activity

PHI’s cash flows for the nine months ended September 30, 2011 and 2010 are summarized below:

	Cash (Use) Source
	2011			2010			Change
	(millions of dollars)
Operating Activities	$	531		$	560		$	(29	)
Investing Activities		(471	)		949			(1,420	)
Financing Activities		22			(1,511	)		1,533
Net increase (decrease) in cash and cash equivalents	$	82		$	(2	)	$	84

Operating Activities

Cash flows from operating activities during the nine months ended September 30, 2011 and 2010 are summarized below:

	Cash (Use) Source
	2011			2010			Change
	(millions of dollars)
Net income from continuing operations	$	237		$	125		$	112
Non-cash adjustments to net income		278			258			20
Gain on early termination of finance leases held in trust		(39	)		—			(39	)
Pension contributions		(110	)		(100	)		(10	)
Changes in cash collateral related to derivative activities		5			(23	)		28
Changes in other assets and liabilities		116			116			—
Changes in Conectiv Energy net assets held for sale		44			184			(140	)
Net cash from operating activities	$	531		$	560		$	(29	)

Net cash from operating activities decreased $29 million for the nine months ended September 30, 2011, compared to the same period in 2010. The decrease was due primarily to a reduction in the Conectiv Energy net assets held for sale. Partially offsetting this decrease in operating cash flows was an increase in cash flows from continuing operations as well as a decrease in collateral requirements that was the result of the on-going wind down of Pepco Energy Services’ retail energy supply business.

Investing Activities

Cash flows from investing activities during the nine months ended September 30, 2011 and 2010 are summarized below:

	Cash (Use) Source
	2011			2010			Change
	(millions of dollars)
Investment in property, plant and equipment	$	(639	)	$	(551	)	$	(88	)
DOE capital reimbursement awards received		27			3			24
Proceeds from sale of Conectiv Energy wholesale power generation business		—			1,635			(1,635	)
Proceeds from early termination of finance leases held in trust		161			—			161
Changes in restricted cash equivalents		(10	)		(2	)		(8	)
Net other investing activities		(10	)		2			(12	)
Investment in property, plant and equipment associated with Conectiv Energy assets held for sale		—			(138	)		138
Net cash (used by) from investing activities	$	(471	)	$	949		$	(1,420	)

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Net cash from investing activities decreased $1,420 million for the nine months ended September 30, 2011 compared to the same period in 2010. The decrease was primarily due to the 2010 proceeds from the sale of the Conectiv Energy wholesale power generation business not recurring in 2011, partially offset by the proceeds from the early termination of certain cross-border energy leases and the absence of any investment in the property, plant and equipment of Conectiv Energy in 2011 after the disposition of the Conectiv Energy business in 2010.

Financing Activities

Cash flows from financing activities during the nine months ended September 30, 2011 and 2010 are summarized below:

	Cash (Use) Source
	2011			2010			Change
	(millions of dollars)
Dividends paid on common stock	$	(183	)	$	(181	)	$	(2	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		36			36			—
Redemption of preferred stock of subsidiaries		(6	)		—			(6	)
Issuances of long-term debt		235			102			133
Reacquisition of long-term debt		(60	)		(1,466	)		1,406
Issuances of short-term debt, net		11			10			1
Net other financing activities		(11	)		(2	)		(9	)
Net financing activities associated with Conectiv Energy assets held for sale		—			(10	)		10
Net cash from (used by) financing activities	$	22		$	(1,511	)	$	1,533

Net cash used by financing activities decreased $1,533 million for the nine months ended September 30, 2011, compared to the same period in 2010, primarily because there was a significant decrease in reacquisitions of long-term debt in 2011 versus the debt extinguishments in 2010.

Redemption of Preferred Stock

On February 25, 2011, ACE redeemed all of its outstanding cumulative preferred stock for approximately $6 million.

Changes in Outstanding Long-Term Debt

Cash flows from the issuance and reacquisition of long-term debt for the nine months ended September 30, 2011 and 2010 are summarized in the charts below:

		2011		2010
Issuances		(millions of dollars)
DPL
	5.4% Tax-exempt bonds due 2031 (a)	$	—	$	78
	0.75% Tax-exempt bonds due 2026 (b)		35		—
ACE
	4.875% Tax-exempt bonds due 2029 (c)		—		23
	4.35% First mortgage bonds due 2021		200		—
Pepco Energy Services			—		1
		$	235	$	102

(a) Consists of Gas Facilities Refunding Revenue Bonds issued by The Delaware Economic Development Authority (DEDA) for the benefit of DPL.

(b) Consists of Pollution Control Refunding Revenue Bonds (DPL Bonds) issued by DEDA for the benefit of DPL that were purchased by DPL in May 2011. See footnote (b) to the Reacquisitions table below. The DPL Bonds were resold to the public in June 2011. While DPL held the DPL Bonds, they remained outstanding as a contractual matter, but were considered extinguished for accounting purposes.

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In connection with the resale of the DPL Bonds, the interest rate on the bonds was changed from 4.9% to a fixed rate of 0.75%. The DPL Bonds are secured by an outstanding series of collateral first mortgage bonds issued by DPL. The collateral first mortgage bonds have maturity dates, optional and mandatory redemption provisions, interest rates and interest payment dates that are identical to the terms of the DPL Bonds. The payment by DPL of its obligations in respect of the DPL Bonds satisfies the corresponding payment obligations on the collateral first mortgage bonds. The DPL Bonds are subject to mandatory purchase by DPL on June 1, 2012.

(c) Consists of Pollution Control Revenue Refunding Bonds (ACE Bonds) issued by The Pollution Control Financing Authority of Salem County for the benefit of ACE that were purchased by ACE in 2008. In connection with the resale by ACE, the interest rate on the ACE Bonds was changed from an auction rate to a fixed rate. The ACE Bonds are secured by an outstanding series of senior notes issued by ACE, and the senior notes are in turn secured by a series of collateral first mortgage bonds issued by ACE. Both the senior notes and the collateral first mortgage bonds have maturity dates, optional and mandatory redemption provisions, interest rates and interest payment dates that are identical to the terms of the ACE Bonds. The payment by ACE of its obligations in respect of the ACE Bonds satisfies the corresponding payment obligations on the senior notes and collateral first mortgage bonds.

		2011		2010
Reacquisitions		(millions of dollars)
Pepco
	5.75% Tax-exempt bonds due 2010 (a)	$	—	$	16
DPL
	4.9% Tax-exempt bonds due 2026 (b)		35		—
	5.5% Tax-exempt bonds due 2025		—		15
	5.65% Tax-exempt bonds due 2028		—		16
			35		31
ACE
	Securitization bonds due 2010-2011		25		24
	7.25% Medium-term notes due 2010		—		1
			25		25
PHI
	4.00% Notes due May 15, 2010		—		200
	Floating Rate Notes due June 1, 2010		—		250
	6.45% Senior Notes due 2012		—		750
	6.125% Senior Notes due 2017		—		129
	7.45% Senior Notes due 2032		—		65
			—		1,394
		$	60	$	1,466

(a) Consists of Pollution Control Revenue Refunding Bonds (Pepco 2010 Bonds) issued by Prince George’s County for the benefit of Pepco. The Pepco 2010 Bonds were secured by an outstanding series of collateral first mortgage bonds issued by Pepco. The collateral first mortgage bonds had maturity dates, optional and mandatory redemption provisions, interest rates and interest payment dates that were identical to the terms of the Pepco 2010 Bonds. Accordingly, the redemption of the Pepco 2010 Bonds at maturity was deemed to be a redemption of the collateral first mortgage bonds.

(b) Repurchased by DPL in May 2011 pursuant to a mandatory purchase provision in the indenture for the bonds that was triggered by the expiration of the original interest period for the bonds. The bonds were resold by DPL in June 2011. See footnote (b) to the Issuances table above.

Capital Requirements

Capital Expenditures

Pepco Holdings’ total capital expenditures for the nine months ended September 30, 2011 totaled $639 million, of which $361 million was incurred by Pepco, $146 million was incurred by DPL and $96 million was incurred by ACE. The remainder was incurred primarily by the PHI Service Company. The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission.

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In PHI’s December 31, 2010 Form 10-K, PHI projected 2011 capital expenditures for the Power Delivery business of $1,072 million. PHI subsequently revised its projected 2011 capital expenditures related to MAPP to defer $90 million to $110 million of the projected 2011 capital expenditures related to MAPP into later years due to the impact of PJM’s change in the in-service date for MAPP. PHI currently anticipates that its total 2011 capital expenditures will be less than its revised projections.

Also as a result of the delay in the MAPP scheduled in-service date, PHI has projected capital expenditures for the Power Delivery business for the five-year period from 2012 through 2016 which is presented below. PHI expects to fund these expenditures through internally generated cash and external financing. If the MAPP project is cancelled at some future date, recovery will occur through the FERC incentive rates that allow recovery of all costs prudently incurred in connection with the project.

	For the Year
	2012			2013			2014		2015		2016		Total
	(millions of dollars)
Power Delivery
Distribution	$	601		$	679		$	729	$	689	$	711	$	3,409
Distribution—Blueprint for the Future		120			3			—		9		92		224
Transmission		305			260			278		255		258		1,356
Transmission—MAPP		5			2			2		6		190		205
Gas Delivery		22			23			23		25		27		120
Other		140			80			50		39		49		358
Sub-Total		1,193			1,047			1,082		1,023		1,327		5,672
DOE Capital Reimbursement Awards (a)		(50	)		(3	)		—		—		—		(53	)
Total for Power Delivery Business	$	1,143		$	1,044		$	1,082	$	1,023	$	1,327	$	5,619

(a) Reflects remaining anticipated reimbursements pursuant to awards from the U.S. Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009.

PHI continues to execute on its plans to enhance reliability at Pepco, DPL and ACE. This is a key driver for success in each of the applicable regulatory jurisdictions to improve the distribution system. The capital investment deemed necessary to improve reliability at Pepco, DPL and ACE is estimated at $1.7 billion for the period from 2012 through 2016 and is included above in the projected capital expenditures. The amount of capital investment required at Pepco, DPL and ACE is estimated at approximately $900 million, $350 million and $400 million, respectively. The total amount of the expenditures may change when anticipated regulations imposing reliability standards are promulgated in Maryland and upon the completion of Pepco’s analysis of the recently adopted modifications to the reliability standards in the District of Columbia.

During the nine months ended September 30, 2011, Pepco and ACE received $27 million and $4 million, respectively, in stimulus funds awarded by the DOE under the American Recovery and Reinvestment Act of 2009. Through September 30, 2011, Pepco and ACE have received $42 million and $6 million, respectively, of the $149 million and $19 million, respectively, that DOE has awarded the companies to fund AMI, direct load control, distribution automation and communication infrastructure in their respective service territories.

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MAPP/DOE Loan Program

To assist in the funding of the MAPP project, PHI has applied for a $684 million loan guarantee from the DOE for a substantial portion of the MAPP project. The application has been made under a federal loan guarantee program for projects that employ innovative energy efficiency, renewable energy and advanced transmission and distribution technologies. If granted, PHI believes the guarantee could allow PHI to acquire financing at a lower cost than it would otherwise be able to obtain in the capital markets. Whether PHI’s application will be granted and, if so, the amount of debt guaranteed is subject to the discretion of the DOE and the negotiation of terms that will satisfy the conditions of the guarantee program. On February 28, 2011, the DOE issued a Notice of Intent to prepare an Environmental Impact Statement to assist the DOE in assessing the environmental impact of constructing the portion of the MAPP project to be supported by the loan guarantee. Since February 2011, the DOE has conducted field inspections of the entire route and has held public meetings to obtain input from the communities along the route. In May 2011, PHI filed for the environmental permit in Maryland and Delaware for the construction of the portion of the line from the Chalk Point substation in Maryland to the Indian River substation in Delaware.

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 (15), “Commitments and Contingencies,” to the Consolidated Financial Statements of PHI included as Part I, Item 1, in this Form 10-Q.

Dividends

On October 27, 2011, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable December 30, 2011 to shareholders of record on December 12, 2011. PHI had approximately $1,114 million and $1,059 million of retained earnings free of restrictions at September 30, 2011 and December 31, 2010, respectively.

Energy Contract Net Asset Activity

The following table provides detail on changes in the net asset or liability positions of both the Pepco Energy Services segment and the former Conectiv Energy segment with respect to energy commodity contracts for the nine months ended September 30, 2011. The balances in the table are pre-tax and the derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

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	Energy Commodity Activities (a)
	(millions of dollars)
Total Fair Value of Energy Contract Net Liabilities at December 31, 2010	$	(218	)
Current period unrealized losses		(10	)
Effective portion of changes in fair value—recorded in Accumulated Other Comprehensive Loss		2
Cash flow hedge ineffectiveness—recorded in income		(1	)
Recognition of realized losses on settlement of contracts		63
Derivative activity associated with Conectiv Energy		83
Total Fair Value of Energy Contract Net Liabilities at September 30, 2011	$	(81	)
Detail of Fair Value of Energy Contract Net Liabilities at September 30, 2011 (see above)
Derivative assets (current assets)	$	9
Derivative assets (non-current assets)		—
Total Fair Value of Energy Contract Assets		9
Derivative liabilities (current liabilities)		(87	)
Derivative liabilities (non-current liabilities)		(3	)
Total Fair Value of Energy Contract Liabilities		(90	)
Total Fair Value of Energy Contract Net Liabilities	$	(81	)

(a) Includes all hedging and trading activities recorded at fair value through Accumulated Other Comprehensive Loss (AOCL) or trading activities recorded at fair value in the Consolidated Statements of Income, as required.

The $81 million net liability on energy contracts at September 30, 2011 was associated with derivatives held by Pepco Energy Services, primarily attributable to losses on power swaps and natural gas futures. Effective February 1, 2011, Conectiv Energy transferred its derivatives to an unaffiliated third party, which contributed $83 million to the reduction in PHI’s overall losses on derivatives from $218 million at December 31, 2010 to $81 million at September 30, 2011. Pepco Energy Services’ net liability decreased to $81 million at September 30, 2011 from $135 million at December 31, 2010 primarily due to settlements of the derivatives. PHI expects that future revenues from existing customer sales obligations that are accounted for on an accrual basis will largely offset Pepco Energy Services’ net liability on energy contracts.

PHI uses its best estimate to determine the fair value of Pepco Energy Services’ commodity derivative contracts. The fair values in each category presented below reflect forward prices and volatility factors as of September 30, 2011 and are subject to change as a result of changes in these factors.

	Fair Value of Contracts at September 30, 2011 Maturities
Source of Fair Value	2011			2012			2013			2014 and Beyond			Total Fair Value
	(millions of dollars)
Energy Commodity Activities, net (a)
Actively Quoted (i.e., exchange-traded) prices	$	(11	)	$	(25	)	$	(7	)	$	(1	)	$	(44	)
Prices provided by other external sources (b)		(11	)		(22	)		(5	)		—			(38	)
Modeled (c)		(1	)		2			—			—			1
Total	$	(23	)	$	(45	)	$	(12	)	$	(1	)	$	(81	)

(a) Includes all effective hedging activities recorded at fair value through AOCL and hedge ineffectiveness and trading activities on the Consolidated Statements of Income, 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 that are readily observable in the market.

(c) Modeled values include significant inputs not readily observable in the market.

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Contractual Arrangements with Credit Rating Triggers or Margining Rights

Under certain contractual arrangements entered into by PHI’s subsidiaries, the subsidiary may be required to provide cash collateral or letters of credit as security for its contractual obligations if the credit ratings of PHI or the subsidiary are downgraded. In the event of a downgrade, the amount required to be posted would depend on the amount of the underlying contractual obligation existing at the time of the downgrade. Based on contractual provisions in effect at September 30, 2011, a downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries to below “investment grade” would increase the collateral obligation of PHI and its subsidiaries by up to $237 million, none of which is related to discontinued operations of Conectiv Energy, and $129 million of which is the net settlement amount attributable to derivatives, normal purchase and normal sale contracts, collateral, and other contracts under master netting agreements as described in Note (13), “Derivative Instruments and Hedging Activities” to the Consolidated Financial Statements of PHI set forth in Part I, Item 1 of this Form 10-Q. The remaining $108 million of the collateral obligation that would be incurred in the event PHI was downgraded to below “investment grade” is attributable primarily to energy services contracts and accounts payable to independent system operators and distribution companies on full requirements contracts entered into by Pepco Energy Services. PHI believes that it and its utility subsidiaries currently have sufficient liquidity to fund their operations and meet their financial obligations.

Many of the contractual arrangements entered into by PHI’s subsidiaries in connection with competitive energy and Default Electricity Supply activities include margining rights pursuant to which the PHI subsidiary or a counterparty may request collateral if the market value of the contractual obligations reaches levels in excess of the credit thresholds established in the applicable arrangements. Pursuant to these margining rights, the affected PHI subsidiary may receive, or be required to post, collateral due to energy price movements. As of September 30, 2011, Pepco Energy Services provided net cash collateral in the amount of $116 million in connection with these activities.

Regulatory and Other Matters

Maryland Public Service Commission New Generation RFP Issuance Requirement

On September 29, 2009, the MPSC initiated an investigation into whether Maryland’s regulated electric distribution companies (EDCs) should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland. On September 29, 2011, the MPSC issued a notice directing each of the four Maryland EDCs, including Pepco and DPL, to issue by October 7, 2011 a request for proposal (RFP) for new generation resources. On that date, Pepco and DPL issued the RFP and sent the MPSC a letter seeking additional information on several aspects of the process established in the notice, and on whether the MPSC will consider a utility-owned generation option.

The MPSC held a pre-offer conference on October 21, 2011, and will hold a hearing on January 31, 2012, to obtain further input on whether it should order investor owned utilities to proceed with the RFP. The notice explicitly states that the MPSC has not made a final determination at this time whether new generation in Maryland is needed.

Pepco and DPL filed a request for rehearing of the notice on October 31, 2011. At this time, PHI cannot predict the effect that the MPSC RFP notice will have on its financial condition or results of operations.

DPL Renewable Energy Portfolio Standards

On July 7, 2011, the Governor of the State of Delaware signed legislation that expands DPL’s Renewable Energy Portfolio Standards (RPS) obligations beginning in 2012 from being required to obtain renewable energy credits (RECs) for energy delivered to SOS customers in Delaware to energy delivered to all of its distribution customers in Delaware. DPL is assessing the impact of the

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change in its REC requirements obligation as a result of the new legislation. However, DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its distribution customers by law.

The legislation also establishes that the energy output from fuel cells manufactured in Delaware capable of running on renewable fuels is an eligible resource for RECs under the Renewable Portfolio Standards Act. The legislation requires that the Delaware Public Service Commission (DPSC) adopt a tariff under which DPL would be an agent that collects payments from its customers and disburses the amounts collected to a Qualified Fuel Cell Provider that deploys Delaware-manufactured fuel cells as part of a 30 megawatt generation facility. The legislation also provides for a reduction in DPL’s REC and solar REC requirements based upon the actual energy output of the 30 megawatt generation facility. On October 18, 2011, the DPSC approved the tariff submitted by DPL. For more information on the tariff, see the section entitled “DPL Renewable Energy Transactions” in Note (2), “Significant Accounting Policies” to the consolidated financial statements of PHI set forth in Part I, Item 1 of this Form 10-Q.

Other

For a discussion of other material pending matters such as regulatory and legal proceedings, and other commitments and contingencies, see Note (15), “Commitments and Contingencies,” to the Consolidated Financial Statements of PHI set forth in Part I, Item 1 of 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, 2010. There have been no material changes to PHI’s critical accounting policies as disclosed in the Form 10-K.

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.

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

Potomac Electric Power Company

Potomac Electric Power Company (Pepco) meets the conditions set forth in General Instruction H to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted.

General Overview

Pepco is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive energy supplier. Default Electricity Supply is known as Standard Offer Service (SOS) in both the District of Columbia and Maryland. Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.2 million. As of September 30, 2011, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to District of Columbia customers.

As a result of the implementation of a bill stabilization adjustment mechanism (BSA) for retail electric customers of Pepco in Maryland in June 2007 and in the District of Columbia in November 2009, Pepco recognizes distribution revenue based on the approved distribution charge per customer. From a revenue recognition standpoint, this has the effect of decoupling distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a consequence, the only factors that will cause distribution revenue in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. For customers to whom the BSA applies, changes in customer usage (such as due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue.

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 (FERC) under PUHCA 2005.

Reliability Enhancement Plans

Pepco continues to execute on its plans to enhance reliability. This is a key driver for success in each of Pepco’s applicable regulatory jurisdictions to improve the distribution system. The capital investment deemed necessary to improve reliability at Pepco is estimated at $900 million for the period from 2012 through 2016. The total amount of the expenditures may change when anticipated regulations imposing reliability standards are promulgated in Maryland and upon the completion of Pepco’s analysis of the recently adopted modifications to the reliability standards in the District of Columbia.

The reliability enhancement plan includes the identification and upgrading of under-performing feeder lines, the addition of new facilities to support load, the installation of distribution automation systems on both the overhead and underground network system, the rejuvenation and replacement of underground residential cables, improvements to substation supply lines and selective undergrounding of portions of existing above ground primary feeder lines, where appropriate to improve reliability. By continuing to focus on these areas, Pepco plans to increase the reliability of the electric system by reducing both the frequency and duration of power outages.

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Blueprint for the Future

Pepco is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. The initiative includes the implementation of various programs to help customers better manage their energy use, reduce the total cost of energy and provide other benefits. These programs also allow each utility to better manage and operate its electrical and natural gas distribution systems.

Significant developments initiated in 2011 include:

• Full-scale implementation of Advanced Metering Infrastructure (AMI) began in the Pepco-Maryland service territory in June 2011.

• On June 15, 2011, Pepco filed a revised tariff in the District of Columbia related to the direct load control programs. This tariff proposes cost recovery through the establishment of a regulatory asset rather than a distribution bill surcharge.

• In March 2011, the Maryland Public Service Commission (MPSC) lifted the suspension on installation of smart thermostats for both Pepco and Delmarva Power & Light Company (DPL) in their Maryland service territories and accordingly smart thermostat installation has commenced.

MAPP Project

In October 2007, the PJM Interconnection, LLC (PJM) Board of Managers approved PHI’s proposal to construct a new 230-mile, 500-kilovolt interstate transmission line referred to as the Mid-Atlantic Power Pathway (MAPP), as part of PJM’s regional transmission expansion plan to address the reliability objectives of the PJM Regional Transmission Organization system. Since that time, there have been various modifications to the proposal that have redefined the length and route of the MAPP project. PJM has approved the use of advanced direct current technology for segments of the project, including the portion of the line that will traverse under the Chesapeake Bay. The direct current portion of the line will be 640 kilovolts and the remainder of the line will be 500 kilovolts. As currently approved by the PJM Board of Managers, MAPP is approximately 152 miles in length originating at the Possum Point substation in Virginia and ending at the Indian River substation in Delaware. The cost of the MAPP project is currently estimated to be $1.2 billion.

On August 18, 2011, PJM notified PHI that the scheduled in-service date for MAPP has been delayed from June 1, 2015 to the 2019 to 2021 time period, to take into account changes in demand response, generation retirements and additions, as well as a revised load forecast for the PJM region that is lower than the load that was forecasted in prior PJM studies. PJM has retained the MAPP project in its 2011 Regional Transmission Expansion Plan (RTEP).

In light of the new in-service date, future revenues associated with the MAPP project would be delayed to later years. The MAPP project is anticipated to earn higher rates of return than PHI’s existing transmission assets. In addition, PHI has requested a temporary delay in the procedural schedules related to the pending applications to construct MAPP in filings with the MPSC and the Virginia State Corporation Commission (VSCC) to the later of one year from August 2011 or the issuance of the 2012 RTEP analysis related to MAPP. In the third quarter of 2011, the MPSC suspended the procedural schedule for MAPP until September 6, 2012. The VSCC has informally indicated to PHI that the VSCC will take no action on PHI’s application to construct MAPP in Virginia until further developments occur with respect to the MAPP project.

The exact revised in-service date of MAPP will be evaluated as part of PJM’s 2012 RTEP review process. Until PJM’s evaluation is concluded, PJM has directed PHI to limit further development efforts with respect to the MAPP project and to proceed with only those development efforts reasonably necessary to allow the MAPP project to be quickly restarted if and when deemed necessary. PHI will be evaluating the work that will be required to support MAPP based on the new in-service date and in accordance with the directives of PJM. During this interim period, PHI intends to continue to complete

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the right-of-way acquisition for the proposed route, and some environmental and other preparatory activities.

Regulatory Lag

The regulatory commissions to which Pepco is subject were established to set utility rates and tariffs with respect to the retail distribution of electricity. These rates are intended to be set, balancing the interests of Pepco’s customers and those of its investors. In order to achieve this balancing, the regulatory commissions must develop rates and tariffs that are reflective of costs during the period in which the rates are in effect, in order to give Pepco the opportunity to generate revenues sufficient to recover its costs, including a reasonable rate of return on investor supplied capital during such period. In designing Pepco’s rate structure, an important factor affecting its ability to earn its authorized rate of return is the willingness of applicable regulatory commissions to adequately recognize costs in such period in order to minimize the delay in recovering increased costs of distribution service. This delay in recovering such increased costs is commonly known as “regulatory lag.” Pepco is currently experiencing significant regulatory lag.

Higher operating and construction costs, including labor, material, depreciation, taxes and financing costs, as well as costs associated with enhanced distribution system reliability and environmental compliance, are expected at Pepco for several years into the future. At the same time, low usage growth and customer growth limits the growth in revenues. This mismatch between high expense growth and low revenue growth increases regulatory lag at Pepco, making it more difficult for Pepco to earn equity returns that are allowed by regulators without higher rates. See “Part II, Item 1A. Risk Factors—The failure of PHI to obtain relief from ‘regulatory lag’ may have a negative effect on PHI’s results of operations and financial condition.”

Pepco anticipates that it will continue to face regulatory lag. In its most recent rate cases, Pepco (in the District of Columbia) has proposed mechanisms that would track reliability and other expenses and permit it between rate cases to make adjustments in its rates for prudent investments as made, thereby seeking to reduce the magnitude of regulatory lag. The District of Columbia Public Service Commission (DCPSC) has not approved these proposed mechanisms, and there can be no assurance that these mechanisms will be approved in whole or in part, if ever. Until such time as these mechanisms are approved, if necessary to address the problem of regulatory lag, Pepco would file rate cases at least annually to align its revenue and related cash flow levels with other operation and maintenance spending and capital investments. In future rate cases, Pepco would also continue to seek cost recovery and tracking mechanisms from applicable regulatory commissions to reduce the effects of regulatory lag.

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Results of Operations

The following results of operations discussion compares the nine months ended September 30, 2011 to the nine months ended September 30, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2011		2010		Change
Regulated T&D Electric Revenue	$	854	$	812	$	42
Default Electricity Supply Revenue		764		958		(194	)
Other Electric Revenue		25		27		(2	)
Total Operating Revenue	$	1,643	$	1,797	$	(154	)

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

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution 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 at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by Pepco at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier, and which is also known as SOS. The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes revenue in the form of transmission enhancement credits that Pepco receives as a transmission owner from PJM for approved regional transmission expansion plan costs.

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally 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

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	258	$	242	$	16
Commercial and industrial		497		480		17
Other		99		90		9
Total Regulated T&D Electric Revenue	$	854	$	812	$	42

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

	2011		2010		Change
Regulated T&D Electric Sales (Gigawatt hours (GWh))
Residential		6,446		6,572		(126	)
Commercial and industrial		14,308		14,564		(256	)
Other		113		113		—
Total Regulated T&D Electric Sales		20,867		21,249		(382	)
	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		711		709		2
Commercial and industrial		74		74		—
Other		—		—		—
Total Regulated T&D Electric Customers		785		783		2

Regulated T&D Electric Revenue increased by $42 million primarily due to:

• An increase of $16 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily resulting from rate increases in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the county.

• An increase of $12 million due to distribution rate increases in the District of Columbia effective March 2010 and July 2010; and in Maryland effective July 2010.

• An increase of $9 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 and June 1, 2011 related to increases in transmission plant investment.

• An increase of $4 million due to customer growth of 1% in 2011, primarily in the residential class.

• An increase of $2 million due to the implementation of the EmPower Maryland (a demand-side management program) surcharge in March 2010 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	555	$	702	$	(147	)
Commercial and industrial		203		246		(43	)
Other		6		10		(4	)
Total Default Electricity Supply Revenue	$	764	$	958	$	(194	)

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	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		5,493		6,002		(509	)
Commercial and industrial		2,200		2,435		(235	)
Other		6		7		(1	)
Total Default Electricity Supply Sales		7,699		8,444		(745	)

	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		612		652		(40	)
Commercial and industrial		46		49		(3	)
Other		—		—		—
Total Default Electricity Supply Customers		658		701		(43	)

Default Electricity Supply Revenue decreased by $194 million primarily due to:

• A decrease of $107 million as a result of lower Default Electricity Supply rates.

• A decrease of $62 million due to lower sales, primarily as a result of residential and commercial customer migration to competitive suppliers.

• A decrease of $37 million due to lower sales as a result of cooler weather during the 2011 spring and summer months as compared to 2010.

The aggregate amount of these decreases was partially offset by:

• An increase of $12 million due to higher non-weather related average customer usage.

• An increase of $3 million resulting from an approval by the DCPSC of an increase in Pepco’s cost recovery rate for providing Default Electricity Supply in the District of Columbia to provide for recovery of higher cash working capital costs incurred in prior periods. The higher cash working capital costs were incurred when the billing cycle for default electricity suppliers was shortened from a monthly to a weekly period, effective in June 2009.

The following table shows the percentages of Pepco’s total distribution sales by jurisdictions that are derived from customers receiving Default Electricity Supply from Pepco. Amounts are for the nine months ended September 30:

	2011			2010
Sales to District of Columbia customers		27	%		30	%
Sales to Maryland customers		44	%		48	%

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Operating Expenses

Purchased Energy

Purchased Energy consists of the cost of electricity purchased by Pepco to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $201 million to $731 million in 2011 from $932 million in 2010 primarily due to:

• A decrease of $127 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $45 million primarily due to customer migration to competitive suppliers.

• A decrease of $33 million due to lower electricity sales primarily as a result of cooler weather during the 2011 spring and summer months as compared to 2010.

Other Operation and Maintenance

Other Operation and Maintenance increased by $61 million to $313 million in 2011 from $252 million in 2010 primarily due to:

• An increase of $25 million primarily due to higher tree trimming and preventative maintenance costs.

• An increase of $12 million primarily due to 2010 adjustments for (i) February 2010 severe winter storm costs of $5 million and (ii) distribution rate case costs of $4 million that previously were charged to other operation and maintenance expense. The adjustments were recorded in accordance with an MPSC rate order issued in August 2010 and a DCPSC rate order issued in February 2010 allowing for the recovery of the costs.

• An increase of $10 million in customer support and communication costs.

• An increase of $4 million primarily due to Pepco’s emergency restoration improvement project and reliability improvement costs.

• An increase of $3 million in emergency restoration costs. The increase is primarily related to the significant incremental costs incurred for repair work following Hurricane Irene in August 2011. Costs incurred for repair work were $14 million, of which $12 million was deferred as a regulatory asset to reflect the probable recovery of these storm costs in certain jurisdictions, and the remaining $2 million was charged to Other operation and maintenance expense. A large portion of the costs of the restoration work associated with Hurricane Irene relates to services provided by outside contractors and other utilities and invoices for such services in most instances have not yet been received and have been estimated. Actual invoices may vary from these estimates.

• An increase of $3 million in legal services, primarily outside counsel fees.

Restructuring Charge

As a result of PHI’s organizational review in the second quarter of 2010, Pepco’s operating expenses include a pre-tax restructuring charge of $6 million for the nine months ended September 30, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

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Depreciation and Amortization

Depreciation and Amortization expenses increased by $7 million to $128 million in 2011 from $121 million in 2010 primarily due to:

• An increase of $3 million in amortization of regulatory assets primarily associated with the EmPower Maryland (a demand-side management program) surcharge that became effective in March 2010 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

• An increase of $3 million due to utility plant additions.

• An increase of $1 million in amortization of software upgrades to Pepco’s Energy Management System.

Other Taxes

Other Taxes increased by $21 million to $294 million in 2011 from $273 million in 2010. The increase was primarily due to:

• An increase of $14 million primarily due to rate increases in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

• An increase of $5 million due to an adjustment recorded in the third quarter of 2010 to correct certain errors related to other taxes.

Effects of Pepco Divestiture-Related Claims

Pepco’s operating expenses include a pre-tax expense of $11 million for the nine months ended September 30, 2010 related to a DCPSC order that disallowed certain items that Pepco had included in the costs it deducted in calculating the net proceeds from the sale of its generation-related assets in 2000.

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $6 million to a net expense of $57 million in 2011 from a net expense of $63 million in 2010. The decrease was primarily due to:

• An increase of $8 million in income related to Allowance for Funds Used During Construction that is applied to capital projects.

• An increase of $3 million in other income due to net proceeds from company owned life insurance policy.

The aggregate amount of these increases was partially offset by:

• A decrease of $3 million in other income due to gains on the sale of four parcels of land in 2010.

Income Tax Expense

Pepco’s effective tax rates for the nine months ended September 30, 2011 and 2010 were 26.7% and 44.6%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions, and a state tax benefit recorded in 2011 related to prior years’ asset dispositions.

During the second quarter of 2011, PHI reached a settlement with the Internal Revenue Service (IRS) with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, Pepco has recorded an additional tax benefit in the

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amount of $5 million (after-tax). This additional interest income was recorded in the second quarter of 2011. This was partially offset by the recalculation of interest on Pepco’s uncertain tax positions for open tax years using different assumptions related to the application of its deposit made with the IRS in 2006. This resulted in an additional tax expense of $1 million (after-tax) in the third quarter of 2011.

In May 2011, Pepco received refunds of approximately $5 million and recorded tax benefits of approximately $4 million (after-tax) related to the filing of amended state tax returns. These amended returns reduced state taxable income as a result of an increase in tax basis on certain prior years’ asset dispositions.

Capital Requirements

Capital Expenditures

Pepco’s capital expenditures for the nine months ended September 30, 2011, totaled $361 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit the Power Delivery business and are allocated to Pepco when the assets are placed in service.

In Pepco’s December 31, 2010 Form 10-K, Pepco projected 2011 capital expenditures for the Power Delivery business of $605 million. Pepco subsequently revised its projected 2011 capital expenditures related to MAPP to defer $65 million to $79 million of the projected 2011 capital expenditures related to MAPP into later years due to the impact of PJM’s change in the in-service date for MAPP. Pepco currently anticipates that its total 2011 capital expenditures will be less than its revised projections.

Also as a result of the delay in the MAPP scheduled in-service date, Pepco has projected capital expenditures for the five-year period from 2012 through 2016 which is presented below. Pepco expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.

	For the Year
	2012	2013	2014		2015		2016		Total
	(millions of dollars)
Pepco
Distribution	$321	$367	$	439	$	398	$	406	$	1,931
Distribution—Blueprint for the Future	76	1		—		—		—		77
Transmission	104	93		68		58		71		394
Transmission—MAPP	1	1		1		3		132		138
Other	56	30		17		13		18		134
Sub-Total	558	492		525		472		627		2,674
DOE Capital Reimbursement Awards (a)	(46)	(2)		—		—		—		(48	)
Total Pepco	$512	$490	$	525	$	472	$	627	$	2,626

(a) Reflects anticipated reimbursements pursuant to awards from the U.S. Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009.

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Pepco continues to execute on its plans to enhance reliability. This is a key driver for success in each of Pepco’s applicable regulatory jurisdictions to improve the distribution system. The capital investment deemed necessary to improve reliability at Pepco is estimated at $900 million for the period from 2012 through 2016 and is included above in the projected capital expenditures. The total amount of the expenditures may change when anticipated regulations imposing reliability standards are promulgated in Maryland and upon the completion of Pepco’s analysis of the recently adopted modifications to the reliability standards in the District of Columbia.

During the nine months ended September 30, 2011, Pepco received $27 million in stimulus funds awarded by the DOE under the American Recovery and Reinvestment Act of 2009. Through September 30, 2011, Pepco received $42 million of the $149 million that DOE has awarded the company to fund AMI, direct load control, distribution automation, and communication infrastructure in its service territories.

MAPP/DOE Loan Program

To assist in the funding of the MAPP project, PHI has applied for a $684 million loan guarantee from the DOE for a substantial portion of the MAPP project. The application has been made under a federal loan guarantee program for projects that employ innovative energy efficiency, renewable energy and advanced transmission and distribution technologies. If granted, PHI believes the guarantee could allow PHI to acquire financing at a lower cost than it would otherwise be able to obtain in the capital markets. Whether PHI’s application will be granted and, if so, the amount of debt guaranteed is subject to the discretion of the DOE and the negotiation of terms that will satisfy the conditions of the guarantee program. On February 28, 2011, the DOE issued a Notice of Intent to prepare an Environmental Impact Statement to assist the DOE in assessing the environmental impact of constructing the portion of the MAPP project to be supported by the loan guarantee. Since February 2011, the DOE has conducted field inspections of the entire route and has held public meetings to obtain input from the communities along the route. In May 2011, PHI filed for the environmental permit in Maryland and Delaware for the construction of the portion of the line from the Chalk Point substation in Maryland to the Indian River substation in Delaware.

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

Delmarva Power & Light Company

Delmarva Power & Light Company (DPL) meets the conditions set forth in General Instruction H to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted.

General Overview

DPL is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland. DPL also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive energy supplier. Default Electricity Supply is known as Standard Offer Service (SOS) in both Delaware and Maryland. DPL’s electricity distribution service territory covers approximately 5,000 square miles and has a population of approximately 1.4 million. As of September 30, 2011, approximately 65% of delivered electricity sales were to Delaware customers and approximately 35% 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 500,000.

As a result of the implementation of a bill stabilization adjustment mechanism (BSA) for retail electric customers of DPL in Maryland in June 2007, DPL recognizes Maryland distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, this has the effect of decoupling distribution revenue recognized in a reporting period with the amount of power delivered during the period. As a consequence, the only factors that will cause distribution revenue in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. For customers to whom the BSA applies, changes in customer usage (such as due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue.

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

Blueprint for the Future

DPL is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. The initiative includes the implementation of various programs to help customers better manage their energy use, reduce the total cost of energy and provide other benefits. These programs also allow each utility to better manage and operate its electrical and natural gas distribution systems.

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Significant developments initiated in 2011 include:

• On July 6, 2011, DPL filed its proposal in Delaware to establish a new residential air-conditioning cycle program which, if approved, would launch in 2012.

• In March 2011, DPL filed its Dynamic Pricing proposal in Delaware. If approved, the program will begin in 2012 with a phase-in stage for customers who participated in the field acceptance tests for AMI.

• In March 2011, the Maryland Public Service Commission (MPSC) lifted the suspension on installation of smart thermostats for both DPL and Potomac Electric Power Company (Pepco) in their Maryland service territories and accordingly smart thermostat installation has commenced.

MAPP Project

In October 2007, the PJM Interconnection, LLC (PJM) Board of Managers approved PHI’s proposal to construct a new 230-mile, 500-kilovolt interstate transmission line referred to as the Mid-Atlantic Power Pathway (MAPP), as part of PJM’s regional transmission expansion plan to address the reliability objectives of the PJM Regional Transmission Organization system. Since that time, there have been various modifications to the proposal that have redefined the length and route of the MAPP project. PJM has approved the use of advanced direct current technology for segments of the project, including the portion of the line that will traverse under the Chesapeake Bay. The direct current portion of the line will be 640 kilovolts and the remainder of the line will be 500 kilovolts. As currently approved by the PJM Board of Managers, MAPP is approximately 152 miles in length originating at the Possum Point substation in Virginia and ending at the Indian River substation in Delaware. The cost of the MAPP project is currently estimated to be $1.2 billion.

On August 18, 2011, PJM notified PHI that the scheduled in-service date for MAPP has been delayed from June 1, 2015 to the 2019 to 2021 time period, to take into account changes in demand response, generation retirements and additions, as well as a revised load forecast for the PJM region that is lower than the load that was forecasted in prior PJM studies. PJM has retained the MAPP project in its 2011 Regional Transmission Expansion Plan (RTEP).

In light of the new in-service date, future revenues associated with the MAPP project would be delayed to later years. The MAPP project is anticipated to earn higher rates of return than PHI’s existing transmission assets. In addition, PHI has requested a temporary delay in the procedural schedules related to the pending applications to construct MAPP in filings with the MPSC and the Virginia State Corporation Commission (VSCC) to the later of one year from August 2011 or the issuance of the 2012 RTEP analysis related to MAPP. In the third quarter of 2011, the MPSC suspended the procedural schedule for MAPP until September 6, 2012. The VSCC has informally indicated to PHI that the VSCC will take no action on PHI’s application to construct MAPP in Virginia until further developments occur with respect to the MAPP project.

The exact revised in-service date of MAPP will be evaluated as part of PJM’s 2012 RTEP review process. Until PJM’s evaluation is concluded, PJM has directed PHI to limit further development efforts with respect to the MAPP project and to proceed with only those development efforts reasonably necessary to allow the MAPP project to be quickly restarted if and when deemed necessary. PHI will be evaluating the work that will be required to support MAPP based on the new in-service date and in accordance with the directives of PJM. During this interim period, PHI intends to continue to complete the right-of-way acquisition for the proposed route, and some environmental and other preparatory activities.

Regulatory Lag

The regulatory commissions to which DPL is subject were established to set utility rates and tariffs with respect to the retail distribution of electricity and natural gas. These rates are intended to be set, balancing the interests of DPL’s customers and those of its investors. In order to achieve this balancing, the regulatory commissions must develop rates and tariffs that are reflective of costs during the period in which the rates are in effect, in order to give DPL the opportunity to generate revenues sufficient to recover its costs, including a reasonable rate of return on investor supplied capital during such period. In designing DPL’s rate structure, an important factor affecting its ability to earn its authorized rate of return is the willingness of applicable regulatory commissions to adequately recognize costs in such period in order to minimize the delay in recovering increased costs of distribution service. This delay in recovering such increased costs is commonly known as “regulatory lag.” DPL is currently experiencing significant regulatory lag.

Higher operating and construction costs, including labor, material, depreciation, taxes and financing costs, as well as costs associated with enhanced distribution system reliability and environmental compliance, are expected at DPL for several years into the future. At the same time, low usage growth and customer growth limits the growth in revenues. This mismatch between high expense growth

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and low revenue growth increases regulatory lag at DPL, making it more difficult for DPL to earn equity returns that are allowed by regulators without higher rates. See “Part II, Item 1A. Risk Factors—The failure of PHI to obtain relief from ‘regulatory lag’ may have a negative effect on PHI’s results of operations and financial condition.”

DPL anticipates that it will continue to face regulatory lag. In its most recent rate case, DPL (in Maryland) has proposed mechanisms that would track reliability and other expenses and permit it between rate cases to make adjustments in its rates for prudent investments as made, thereby seeking to reduce the magnitude of regulatory lag. The MPSC has not approved these proposed mechanisms, and there can be no assurance that these mechanisms will be approved in whole or in part, if ever. Until such time as these mechanisms are approved, if necessary to address the problem of regulatory lag, DPL would file rate cases at least annually to align its revenue and related cash flow levels with other operation and maintenance spending and capital investments. In future rate cases, DPL would also continue to seek cost recovery and tracking mechanisms from applicable regulatory commissions to reduce the effects of regulatory lag.

Reliability Enhancement Plans

DPL continues to execute on its plans to enhance reliability. This is a key driver for success in each of DPL’s applicable regulatory jurisdictions to improve the distribution system. The capital investment deemed necessary to improve reliability at DPL is estimated at $350 million for the period from 2012 through 2016. The total amount of the expenditures may change when anticipated regulations imposing reliability standards are promulgated in Maryland.

The reliability enhancement plan includes the identification and upgrading of under-performing feeder lines, the addition of new facilities to support load, the installation of distribution automation systems on both the overhead and underground network system, the rejuvenation and replacement of underground residential cables, improvements to substation supply lines and selective undergrounding of portions of existing above ground primary feeder lines, where appropriate to improve reliability. By continuing to focus on these areas, DPL plans to increase the reliability of the electric system by reducing both the frequency and duration of power outages.

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Results of Operations

The following results of operations discussion compares the nine months ended September 30, 2011 to the nine months ended September 30, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Electric Operating Revenue

	2011		2010		Change
Regulated T&D Electric Revenue	$	299	$	279	$	20
Default Electricity Supply Revenue		531		607		(76	)
Other Electric Revenue		11		15		(4	)
Total Electric Operating Revenue	$	841	$	901	$	(60	)

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

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution 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 at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by DPL at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier, and which is also known as SOS. The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes transmission enhancement credits that DPL receives as a transmission owner from PJM for approved regional transmission expansion plan costs.

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally 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

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	144	$	139	$	5
Commercial and industrial		84		81		3
Other		71		59		12
Total Regulated T&D Electric Revenue	$	299	$	279	$	20

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

	2011		2010		Change
Regulated T&D Electric Sales (Gigawatt hours (GWh))
Residential		4,121		4,186		(65	)
Commercial and industrial		5,610		5,615		(5	)
Other		36		37		(1	)
Total Regulated T&D Electric Sales		9,767		9,838		(71	)
	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		441		440		1
Commercial and industrial		59		59		—
Other		1		1		—
Total Regulated T&D Electric Customers		501		500		1

Regulated T&D Electric Revenue increased by $20 million primarily due to:

• An increase of $12 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 and June 1, 2011 related to increases in transmission plant investment.

• An increase of $11 million due to distribution rate increases in Maryland effective July 2011, and in Delaware effective April 2010 and February 2011.

The aggregate amount of these increases was partially offset by:

• A decrease of $2 million due to lower sales as a result of cooler weather during the 2011 spring and summer months as compared to 2010.

Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	406	$	459	$	(53	)
Commercial and industrial		116		140		(24	)
Other		9		8		1
Total Default Electricity Supply Revenue	$	531	$	607	$	(76	)
	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		3,861		4,081		(220	)
Commercial and industrial		1,392		1,482		(90	)
Other		22		29		(7	)
Total Default Electricity Supply Sales		5,275		5,592		(317	)

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	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		416		429		(13	)
Commercial and industrial		43		46		(3	)
Other		—		1		(1	)
Total Default Electricity Supply Customers		459		476		(17	)

Default Electricity Supply Revenue decreased by $76 million primarily due to:

• A decrease of $44 million as a result of lower Default Electricity Supply rates.

• A decrease of $26 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

• A decrease of $15 million due to lower sales as a result of cooler weather during the 2011 spring and summer months as compared to 2010.

The aggregate amount of these decreases was partially offset by:

• An increase of $7 million due to higher non-weather related average customer usage.

The following table shows the percentages of DPL’s total distribution sales by jurisdictions that are derived from customers receiving Default Electricity Supply from DPL. Amounts are for the nine months ended September 30:

	2011			2010
Sales to Delaware customers		51	%		53	%
Sales to Maryland customers		59	%		64	%

Natural Gas Operating Revenue

	2011		2010		Change
Regulated Gas Revenue	$	134	$	127	$	7
Other Gas Revenue		35		39		(4	)
Total Natural Gas Operating Revenue	$	169	$	166	$	3

The table above shows the amounts of Natural Gas Operating Revenue from sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other Gas Revenue includes off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

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Regulated Gas

	2011		2010			Change
Regulated Gas Revenue
Residential	$	82	$	78		$	4
Commercial and industrial		45		44			1
Transportation and other		7		5			2
Total Regulated Gas Revenue	$	134	$	127		$	7
					��
	2011		2010			Change
Regulated Gas Sales (billion cubic feet)
Residential		6		5			1
Commercial and industrial		3		3			—
Transportation and other		5		5			—
Total Regulated Gas Sales		14		13			1
	2011		2010			Change
Regulated Gas Customers (in thousands)
Residential		114		113			1
Commercial and industrial		9		10			(1	)
Transportation and other		—		—			—
Total Regulated Gas Customers		123		123			—

Regulated Gas Revenue increased by $7 million primarily due to:

• An increase of $18 million due to higher sales primarily as a result of colder weather during the 2011 winter months as compared to 2010.

• An increase of $2 million due to a distribution rate increase effective February 2011.

The aggregate amount of these increases was partially offset by:

• A decrease of $13 million due to lower non-weather related average customer usage.

Other Gas Revenue

Other Gas Revenue decreased by $4 million primarily due to lower volumes of off-system sales to electric generators and gas marketers.

Operating Expenses

Purchased Energy

Purchased Energy consists of the cost of electricity purchased by DPL to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $78 million to $507 million in 2011 from $585 million in 2010 primarily due to:

• A decrease of $42 million due to lower average electricity costs under Default Electricity Supply contracts.

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• A decrease of $18 million primarily due to customer migration to competitive suppliers.

• A decrease of $12 million due to lower electricity sales primarily as a result of cooler weather during the 2011 spring and summer months as compared to 2010.

• A decrease of $6 million in deferred electricity expense primarily due to lower Default Electricity Supply rates, which resulted in a lower rate of recovery of Default Electricity Supply costs.

Gas Purchased

Gas Purchased consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales. Total Gas Purchased decreased by $3 million to $114 million in 2011 from $117 million in 2010 primarily due to:

• A decrease of $10 million in the cost of gas purchases for on-system sales as a result of lower average gas prices and lower withdrawals from storage.

• A decrease of $8 million from the settlement of financial hedges entered into as part of DPL’s hedge program for regulated natural gas.

• A decrease of $3 million in the cost of gas purchases for off-system sales as a result of lower volumes purchased.

The aggregate amount of these decreases was partially offset by:

• An increase of $18 million in deferred gas expense as a result of a higher rate of recovery of natural gas supply costs.

Other Operation and Maintenance

Other Operation and Maintenance decreased by $10 million to $181 million in 2011 from $191 million in 2010 primarily due to:

• A decrease of $10 million associated with $8 million and $2 million adjustments recorded by DPL in the second and third quarter of 2011, respectively, associated with the accounting for DPL Default Electricity Supply. These adjustments were primarily due to the under-recognition of allowed returns on working capital and administrative costs.

• A decrease of $4 million due to 2010 environmental remediation costs related to a 1999 oil release at the Indian River generating facility then owned by DPL, as further discussed under “Indian River Oil Release” in Note (12), “Commitments and Contingencies” to the financial statements of DPL.

• A decrease of $2 million due to an adjustment of self-insurance reserves for general and auto liability claims recorded in 2011.

• A decrease of $2 million primarily due to an adjustment for February 2010 severe winter storm costs that previously were charged to other operation and maintenance expense. The adjustment was recorded in accordance with an MPSC rate order issued in July 2011, allowing for the recovery of the costs.

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The aggregate amount of these decreases was partially offset by:

• An increase of $5 million in emergency restoration costs. The increase is primarily related to the significant incremental costs incurred for repair work following Hurricane Irene in August 2011. Costs incurred for repair work were $9 million, of which $5 million was deferred as a regulatory asset to reflect the probable recovery of these storm costs in certain jurisdictions, and the remaining $4 million was charged to Other operation and maintenance expense. A large portion of the costs of the restoration work associated with Hurricane Irene relates to services provided by outside contractors and other utilities and invoices for such services in most instances have not yet been received and have been estimated. Actual invoices may vary from these estimates.

• An increase of $5 million primarily due to higher preventative maintenance and tree trimming costs.

Restructuring Charge

As a result of PHI’s organizational review in the second quarter of 2010, DPL’s operating expenses include a pre-tax restructuring charge of $4 million for the nine months ended September 30, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

Depreciation and Amortization

Depreciation and Amortization expenses increased by $4 million to $66 million in 2011, from $62 million in 2010 primarily due to:

• An increase of $3 million due to utility plant additions.

• An increase of $1 million in amortization of regulatory assets primarily associated with the EmPower Maryland (a demand-side management program) surcharge that became effective in March 2010 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

Income Tax Expense

DPL’s effective tax rates for the nine months ended September 30, 2011 and 2010 were 36.4% and 44.2%, respectively. The decrease in the effective tax rate resulted from changes in estimates and interest related to uncertain and effectively settled tax positions, primarily related to the $2 million reversal of accrued interest income on state income tax positions recorded in 2010 that DPL no longer believes is more likely than not to be realized, and an additional $2 million interest benefit recorded in 2011 from the reallocation of deposits discussed below.

During the second quarter of 2011, PHI reached a settlement with the Internal Revenue Service (IRS) with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, DPL recorded additional interest income of $4 million (after-tax) in the second quarter of 2011. This benefit is partially offset by the adjustments recorded in the third quarter of 2011 related to DPL’s settlement with the state taxing authorities resulting in $1 million (after-tax) of additional tax expense and tax expense of $1 million (after-tax) associated with the recalculation of interest on its uncertain tax positions for open tax years using different assumptions related to the application of its deposit made with the IRS in 2006.

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Capital Requirements

Capital Expenditures

DPL’s capital expenditures for the nine months ended September 30, 2011, totaled $146 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit the Power Delivery business and are allocated to DPL when the assets are placed in service.

In DPL’s December 31, 2010 Form 10-K, DPL projected 2011 capital expenditures for the Power Delivery business of $308 million. DPL subsequently revised its projected 2011 capital expenditures related to MAPP to defer $25 million to $31 million of the projected 2011 capital expenditures related to MAPP into later years due to the impact of PJM’s change in the in-service date for MAPP. DPL currently anticipates that its total 2011 capital expenditures will be less than its revised projections.

Also as a result of the delay in the MAPP scheduled in-service date, DPL has projected capital expenditures for the five-year period from 2012 through 2016 which is presented below. DPL expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.

	For the Year
	2012		2013		2014		2015		2016		Total
	(millions of dollars)
DPL
Distribution	$	136	$	153	$	144	$	144	$	161	$	738
Distribution—Blueprint for the Future		44		2		—		—		—		46
Transmission		148		93		128		120		116		605
Transmission—MAPP		4		1		1		3		58		67
Gas Delivery		22		23		23		25		27		120
Other		52		29		20		14		17		132
Total DPL	$	406	$	301	$	316	$	306	$	379	$	1,708

DPL continues to execute on its plans to enhance reliability. This is a key driver for success in each of DPL’s applicable regulatory jurisdictions to improve the distribution system. The capital investment deemed necessary to improve reliability at DPL is estimated at $350 million for the period from 2012 through 2016 and is included above in the projected capital expenditures. The total amount of the expenditures may change when anticipated regulations imposing reliability standards are promulgated in Maryland.

MAPP/DOE Loan Program

To assist in the funding of the MAPP project, PHI has applied for a $684 million loan guarantee from the United States Department of Energy (DOE) for a substantial portion of the MAPP project. The application has been made under a federal loan guarantee program for projects that employ innovative energy efficiency, renewable energy and advanced transmission and distribution technologies. If granted, PHI believes the guarantee could allow PHI to acquire financing at a lower cost than it would otherwise be able to obtain in the capital markets. Whether PHI’s application will be granted and, if so, the amount of debt guaranteed is subject to the discretion of the DOE and the negotiation of terms that will satisfy the conditions of the guarantee program. On February 28, 2011, the DOE issued a Notice of

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Intent to prepare an Environmental Impact Statement to assist the DOE in assessing the environmental impact of constructing the portion of the MAPP project to be supported by the loan guarantee. Since February 2011, the DOE has conducted field inspections of the entire route and has held public meetings to obtain input from the communities along the route. In May 2011, PHI filed for the environmental permit in Maryland and Delaware for the construction of the portion of the line from the Chalk Point substation in Maryland to the Indian River substation in Delaware.

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ACE

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

Atlantic City Electric Company

Atlantic City Electric Company (ACE) meets the conditions set forth in General Instruction H to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted.

General Overview

ACE is engaged in the transmission and distribution of electricity in southern New Jersey. ACE also 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 energy supplier. Default Electricity Supply is 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, LLC, which is wholly owned by Pepco Holdings, Inc. (PHI or Pepco Holdings). Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between PHI and ACE and certain activities of ACE are subject to the regulatory oversight of the Federal Energy Regulatory Commission (FERC) under PUHCA 2005.

Blueprint for the Future

ACE is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. The initiative includes the implementation of various programs to help customers better manage their energy use, reduce the total cost of energy and provide other benefits. These programs also allow each utility to better manage and operate its electrical and gas distribution systems. The New Jersey Board of Public Utilities (NJBPU) is not expected to approve ACE’s proposal for implementation of advanced meters in the near term.

Regulatory Lag

The NJBPU was established to set utility rates and tariffs with respect to the retail distribution of electricity. These rates are intended to be set, balancing the interests of ACE’s customers and those of its investors. In order to achieve this balancing, the NJBPU must develop rates that are reflective of costs during the period in which the rates are in effect, in order to give ACE the opportunity to generate revenues sufficient to recover its costs, including a reasonable rate of return on investor supplied capital during such period. An important factor affecting ACE’s ability to earn its authorized rate of return is the willingness of the NJBPU to adequately recognize forward-looking costs in designing ACE’s rate structure in order to minimize the delay in recovering increased costs of distribution service. This delay in recovering such increased costs is commonly known as “regulatory lag.” ACE is currently experiencing significant regulatory lag.

Higher operating and construction costs, including labor, material, depreciation, taxes and financing costs, as well as costs associated with enhanced distribution system reliability and environmental compliance, are expected at ACE for several years into the future. At the same time, low usage growth and customer growth limits the growth in revenues. This mismatch between high expense growth and low revenue growth increases regulatory lag at ACE, making it more difficult for ACE to earn equity returns that are allowed by the NJBPU without higher rates. See “Part II, Item 1A. Risk Factors—The failure of PHI to obtain relief from ‘regulatory lag’ may have a negative effect on PHI’s results of operations and financial condition.”

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ACE

ACE anticipates that it will continue to face regulatory lag. The NJBPU has approved certain rate recovery mechanisms in connection with ACE’s Infrastructure Investment Program (the IIP), which was originally approved by the NJBPU in July 2009. In exchange for the increase in infrastructure investment, the NJBPU through the IIP allowed recovery of ACE’s infrastructure investment capital expenditures through a special rate outside the normal rate recovery mechanism in a base rate filing. On October 18, 2011, ACE filed a petition with the NJBPU for approval of an extension and expansion to the IIP. However, there can be no assurance that such petition or any other attempts by ACE to mitigate regulatory lag in its New Jersey base rate cases will be approved, or that even if approved, the rate recovery mechanisms in the IIP or any base rate cases will fully ameliorate the effects of regulatory lag on ACE. If necessary to address the problem of regulatory lag in whole or in part, ACE would file rate cases annually to align its revenue and related cash flow levels with other operation and maintenance spending and capital investments. In future rate cases, ACE would also continue to seek cost recovery and tracking mechanisms from the NJBPU to reduce further the effects of regulatory lag.

Reliability Enhancement Plans

ACE continues to execute on its plan to enhance reliability. This is a key driver for success to improve the distribution system. The capital investment deemed necessary to improve reliability at ACE is estimated at $400 million for the period from 2012 through 2016.

The reliability enhancement plan includes the identification and upgrading of under-performing feeder lines, the addition of new facilities to support load, the installation of distribution automation systems on both the overhead and underground network system, the rejuvenation and replacement of underground residential cables, improvements to substation supply lines and selective undergrounding of portions of existing above ground primary feeder lines, where appropriate to improve reliability. By continuing to focus on these areas, ACE plans to increase the reliability of the electric system by reducing both the frequency and duration of power outages.

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ACE

Results of Operations

The following results of operations discussion compares the nine months ended September 30, 2011 to the nine months ended September 30, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2011		2010		Change
Regulated T&D Electric Revenue	$	303	$	322	$	(19	)
Default Electricity Supply Revenue		701		815		(114	)
Other Electric Revenue		14		13		1
Total Operating Revenue	$	1,018	$	1,150	$	(132	)

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

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution 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) at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by ACE at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier, also known as BGS. The costs related to Default Electricity Supply are included in “Purchased energy.” Default Electricity Supply Revenue also includes revenue from Transition Bond Charges that ACE receives, and pays to Atlantic City Electric Transition Funding, LLC (ACE Funding), to fund the principal and interest payments on bonds issued by ACE Funding (Transition Bonds) and revenue in the form of transmission enhancement credits that ACE receives as a transmission owner from PJM for approved regional transmission expansion plan costs (Transmission Enhancement Credits).

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally 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

	2011		2010		Change
Regulated T&D Electric Revenue
Residential	$	137	$	148	$	(11	)
Commercial and industrial		95		107		(12	)
Other		71		67		4
Total Regulated T&D Electric Revenue	$	303	$	322	$	(19	)

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

	2011		2010		Change
Regulated T&D Electric Sales (Gigawatt hours (GWh))
Residential		3,647		3,763		(116	)
Commercial and industrial		3,987		4,136		(149	)
Other		32		32		—
Total Regulated T&D Electric Sales		7,666		7,931		(265	)
	2011		2010		Change
Regulated T&D Electric Customers (in thousands)
Residential		482		482		—
Commercial and industrial		65		65		—
Other		1		1		—
Total Regulated T&D Electric Customers		548		548		—

Regulated T&D Electric Revenue decreased by $19 million primarily due to:

• A decrease of $24 million due to a New Jersey Societal Benefit Charge rate decrease that became effective in January 2011 (which is offset in Deferred Electric Service Costs).

• A decrease of $4 million due to lower sales as a result of cooler weather during the 2011 spring and summer months as compared to 2010.

• A decrease of $4 million due to lower non-weather related average customer usage.

The aggregate amount of these decreases was partially offset by:

• An increase of $9 million due to a distribution rate increase that became effective in June 2010.

• An increase of $4 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 and June 1, 2011 related to increases in transmission plant investment.

Default Electricity Supply

	2011		2010		Change
Default Electricity Supply Revenue
Residential	$	402	$	483	$	(81	)
Commercial and industrial		189		195		(6	)
Other		110		137		(27	)
Total Default Electricity Supply Revenue	$	701	$	815	$	(114	)

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ACE

Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale in the PJM Regional Transmission Organization market of energy and capacity purchased under contracts with unaffiliated, non-utility generators (NUGs), and (ii) revenue from Transmission Enhancement Credits.

	2011		2010		Change
Default Electricity Supply Sales (GWh)
Residential		3,214		3,736		(522	)
Commercial and industrial		1,161		1,575		(414	)
Other		26		32		(6	)
Total Default Electricity Supply Sales		4,401		5,343		(942	)
	2011		2010		Change
Default Electricity Supply Customers (in thousands)
Residential		423		473		(50	)
Commercial and industrial		50		57		(7	)
Other		1		1		—
Total Default Electricity Supply Customers		474		531		(57	)

Default Electricity Supply Revenue decreased by $114 million primarily due to:

• A decrease of $86 million due to lower sales, primarily as a result of commercial and residential customer migration to competitive suppliers.

• A decrease of $24 million in wholesale energy and capacity resale revenues primarily due to the sale of lower volumes of electricity and capacity purchased from NUGs.

• A decrease of $14 million due to lower sales as a result of cooler weather during the 2011 spring and summer months as compared to 2010.

• A decrease of $4 million due to lower non-weather related average customer usage.

• A decrease of $3 million due to a decrease in revenue from Transmission Enhancement Credits.

The aggregate amount of these decreases was partially offset by:

• An increase of $17 million as a result of higher Default Electricity Supply rates, primarily due to a Non-utility Generation Charge rate increase that became effective in January 2011.

The decrease in total Default Electricity Supply Revenue includes a decrease of $12 million in unbilled revenue attributable to ACE’s BGS. Under the BGS terms approved by the NJBPU, ACE is entitled to recover from its customers all of its costs of providing BGS. If the costs of providing BGS exceed the BGS revenue, the excess costs are deferred in Deferred Electric Service Costs. ACE’s BGS unbilled revenue is not included in the deferral calculation, and therefore has an impact on the results of operations in the period during which it is accrued. While the change in the amount of unbilled revenue from year to year typically is not significant, for the nine months ended September 30, 2011, BGS unbilled revenue decreased by $12 million as compared to the nine months ended September 30, 2010, which resulted in a $7 million decrease in ACE’s net income. The decrease was primarily due to lower Default Electricity Supply rates and lower customer usage during the unbilled revenue period at the end of the nine months ended September 30, 2011, as compared to the corresponding period in 2010.

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ACE

For the nine months ended September 30, 2011 and 2010, the percentages of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 57% and 67%, respectively.

Operating Expenses

Purchased Energy

Purchased Energy consists of the cost of electricity purchased by ACE to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $171 million to $648 million in 2011 from $819 million in 2010 primarily due to:

• A decrease of $109 million primarily due to customer migration to competitive suppliers.

• A decrease of $52 million due to lower average electricity costs under Default Electricity Supply contracts.

• A decrease of $9 million due to lower electricity sales primarily as a result of cooler weather during the 2011 spring and summer months as compared to 2010.

Other Operation and Maintenance

Other Operation and Maintenance increased by $16 million to $167 million in 2011 from $151 million in 2010. Excluding an increase of $4 million primarily related to New Jersey Societal Benefit Program costs that are deferred and recoverable, Other Operation and Maintenance expense increased by $12 million. The $12 million increase was primarily due to:

• An increase of $8 million primarily due to higher tree trimming and preventative maintenance costs.

• An increase of $3 million in employee-related costs, primarily due to higher accrued vacation and other benefit expenses.

• An increase of $2 million in costs related to customer requested work.

The aggregate amount of these increases was partially offset by:

• A decrease of $4 million in emergency restoration cost due to higher storm activity in 2010, primarily the severe winter storms of February 2010. ACE incurred significant incremental storm restoration costs for repair work in the nine months ended September 30, 2011 following Hurricane Irene of $7 million but such costs were deferred as a regulatory asset to reflect the probable recovery of these storm costs.

Restructuring Charge

As a result of PHI’s organizational review in the second quarter of 2010, ACE’s operating expenses include a pre-tax restructuring charge of $3 million for the nine months ended September 30, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

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ACE

Depreciation and Amortization

Depreciation and Amortization expense increased by $26 million to $107 million in 2011 from $81 million in 2010 primarily due to:

• An increase of $21 million in amortization of stranded costs as the result of higher revenue due to rate increases effective October 2010 for the ACE Transition Bond Charge and the Market Transition Charge Tax (partially offset in Default Electricity Supply Revenue).

• An increase of $5 million due to utility plant additions.

Deferred Electric Service Costs

Deferred Electric Service Costs represent (i) the over or under recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the over or under recovery of New Jersey Societal Benefit Program costs incurred by ACE. The cost of electricity purchased is reported under Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of New Jersey Societal Benefit Programs is reported under Other Operation and Maintenance, and the corresponding revenue is reported under Regulated T&D Electric Revenue.

Deferred Electric Service Costs increased by $20 million, to an expense reduction of $49 million in 2011 as compared to an expense reduction of $69 million in 2010, primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply rates and lower electricity supply costs.

Income Tax Expense

ACE’s consolidated effective tax rates for the nine months ended September 30, 2011 and 2010 were 46.8% and 44.3%, respectively. The increase in the effective tax rate primarily resulted from ACE’s reconciliation of deferred taxes on certain regulatory assets which resulted in a $1 million increase to income tax expense in 2011.

During the second quarter of 2011, PHI reached a settlement with the Internal Revenue Service (IRS) with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, ACE has recorded an additional $1 million (after-tax) of interest due to the IRS. This additional interest expense was recorded in the second quarter of 2011. This is further impacted by the adjustment recorded in the third quarter of 2011 related to the recalculation of interest on its uncertain tax positions for open tax years using different assumptions related to the application of its deposit made with the IRS in 2006.

Also, during the first quarter of 2010, ACE recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment resulted in an increase in income tax expense of $6 million for the nine months ended September 30, 2010. The adjustment represents the reversal of erroneously recorded interest income for state income tax purposes related to uncertain and effectively settled tax positions, including $2 million, $3 million and $1 million recorded in 2009, 2008 and 2007, respectively.

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ACE

Capital Requirements

Capital Expenditures

ACE’s capital expenditures for the nine months ended September 30, 2011, totaled $96 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit the Power Delivery business and are allocated to ACE when the assets are placed in service.

The following table shows ACE’s updated projected capital expenditures for the five-year period from 2012 through 2016. ACE expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.

	For the Year
	2012			2013			2014		2015		2016		Total
	(millions of dollars)
ACE
Distribution	$	144		$	159		$	146	$	147	$	144	$	740
Distribution—Blueprint for the Future		—			—			—		9		92		101
Transmission		53			74			82		77		71		357
Other		32			21			13		12		14		92
Sub-Total		229			254			241		245		321		1,290
DOE Capital Reimbursement Awards (a)		(4	)		(1	)		—		—		—		(5	)
Total ACE	$	225		$	253		$	241	$	245	$	321	$	1,285

(a) Reflects anticipated reimbursements pursuant to awards from the U.S. Department of Energy under the American Recovery and Reinvestment Act of 2009.

ACE continues to execute on its plan to enhance reliability. This is a key driver for success to improve the distribution system. The capital investment deemed necessary to improve reliability at ACE is estimated at $400 million for the period from 2012 through 2016 and is included above in the projected capital expenditures.

During the nine months ended September 30, 2011, ACE received $4 million in stimulus funds awarded by the United States Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009. Through September 30, 2011, ACE has received $6 million of the $19 million that DOE awarded the company to fund advanced metering infrastructure, direct load control, distribution automation, and communication infrastructure in its service territories.

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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 otherwise disclosed in this Form 10-Q, refer to Note (2), “Significant Accounting Policies—Accounting For Derivatives,” and Note (15), “Derivative Instruments and Hedging Activities,” of the consolidated financial statements of PHI included in its Annual Report on Form 10-K for the year ended December 31, 2010, “Part I, Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in PHI’s Annual Report on Form 10-K for the year ended December 31, 2010, and Note (13), “Derivative Instruments and Hedging Activities,” of the consolidated financial statements of PHI included herein.

Pepco Holdings, Inc.

Commodity Price Risk

The Pepco Energy Services segment engages in commodity risk management activities to reduce its financial exposure to changes in the value of its assets and obligations due to commodity price fluctuations. Certain of these risk management activities are conducted using instruments classified as derivatives based on Financial Accounting Standards Board (FASB) guidance on derivatives and hedging, Accounting Standards Codification 815. Pepco Energy Services also manages commodity risk with contracts that are not classified as derivatives. The primary risk management objective is to manage the spread between retail electricity and natural gas supply commitments and the cost of energy used to service those commitments in order to ensure stable and known cash flows and fix favorable prices and margins.

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 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 the energy commodity activities of Pepco Energy Services. PHI also uses other measures to limit and monitor risk in its energy 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 uses a delta-gamma VaR estimation model. The other parameters include a 95 percent, one-tailed confidence level and 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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The table below provides the VaR associated with energy contracts of the Pepco Energy Services segment for the nine months ended September 30, 2011 in millions of dollars:

	VaR (a)
95% confidence level, one-day holding period, one-tailed
Period end	$	1
Average for the period	$	1
High	$	3
Low	$	1

(a) This column represents all energy derivative contracts, normal purchase and normal sales contracts, modeled generation output and fuel requirements, and modeled customer load obligations for Pepco Energy Services’ energy commodity activities.

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 distribution to customers. Pepco Energy Services accounts for its derivatives as either cash flow hedges of forecasted transactions or they are marked to market through current earnings. Forward contracts that meet the requirements for normal purchase and normal sale accounting under FASB guidance on derivatives and hedging are recorded on an accrual basis.

Credit and Nonperformance Risk

The following table provides information on the credit exposure on wholesale energy contracts, net of collateral, to wholesale counterparties as of September 30, 2011, in millions of dollars:

Rating	Exposure  Before Credit Collateral (b)		Credit Collateral  (c)		Net Exposure		Number of Counterparties Greater Than 10% (d)		Net Exposure  of Counterparties Greater Than  10%
Investment Grade (a)	$	—	$	—	$	—		—	$	—
Non-Investment Grade		—		—		—		—		—
No External Ratings		1		—		1		1		1
Credit reserves						—

(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.

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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, 2010.

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

Conclusions Regarding the Effectiveness of Disclosure Controls and Procedures

Each Reporting Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in such Reporting Company’s reports under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to management of such Reporting Company, including the Reporting Company’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO), as appropriate, to allow timely decisions regarding required disclosure. This control system, no matter how well designed and operated, can provide only reasonable assurance that the objectives of the control system are met. Such Reporting Company’s disclosure controls and procedures were designed to provide reasonable assurance of achieving their stated objectives. Under the supervision, and with the participation of management, including the CEO and the CFO, each Reporting Company has evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2011, and, based upon this evaluation, the CEO and the CFO of such Reporting Company have concluded that these disclosure controls and procedures are effective to provide reasonable assurance that material information relating to such Reporting Company 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 CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Reports of Changes in Internal Control Over Financial Reporting

Under the supervision and with the participation of management, including the CEO and CFO of each Reporting Company, each such Reporting Company has evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended September 30, 2011, and has concluded there was no change in such Reporting Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, such Reporting Company’s internal control over financial reporting.

Part II OTHER INFORMATION

Item  1. LEGAL PROCEEDINGS

Pepco Holdings

Other than ordinary routine litigation incidental to its and its subsidiaries’ business, PHI is not a party to, and its subsidiaries’ property is not subject to, any material pending legal proceedings except as described in Note (15), “Commitments and Contingencies,” to the Consolidated Financial Statements of PHI included herein, which description is incorporated by reference 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,” to the Financial Statements of Pepco included herein, which description is incorporated by reference herein.

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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 (12), “Commitments and Contingencies,” to the Financial Statements of DPL included herein, which description is incorporated by reference 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 (11), “Commitments and Contingencies,” to the Consolidated Financial Statements of ACE included herein, which description is incorporated by reference herein.

Item  1A. RISK FACTORS

For a discussion of the risk factors applicable to each Reporting Company, please refer to “Part I, Item 1A. Risk Factors” in each Reporting Company’s Annual Report on Form 10-K for the year ended December 31, 2010 (the 2010 Form 10-K), the risk factors contained herein, and the risk factors contained in each Reporting Company’s Form 10-Q for each of the quarters ended March 31 and June 30, 2011 (the March and June 2011 Form 10-Qs). There have been no material changes to any Reporting Company’s risk factors as disclosed in the 2010 Form 10-K, except as set forth below and in the March and June 2011 Form 10-Qs.

(1) Each of the following risk factors supersedes the risk factor with the same heading in the 2010 Form 10-K (and, as applicable, the March and June 2011 Form 10-Qs). Except as otherwise noted, each risk factor set forth below applies to each of Pepco Holdings, Pepco, DPL and ACE:

Energy companies are subject to adverse publicity which makes them vulnerable to negative regulatory and litigation outcomes.

Utility companies, including PHI’s utility subsidiaries, have been the subject of public criticism focused on the reliability of their distribution services and the speed with which they are able to respond to outages caused by storm damage. Adverse publicity of this nature may render legislatures, regulatory authorities and other government officials less likely to view energy companies such as PHI and its subsidiaries in a favorable light, and may cause PHI and its subsidiaries to be susceptible to less favorable legislative and regulatory outcomes. In this regard, in April 2011, Maryland adopted legislation under which electric utilities operating in Maryland, including Pepco and DPL, could be subject to fines for failure to meet minimum service quality and reliability standards to be developed by the MPSC. In July 2011, the DCPSC adopted regulations that raise the minimum service reliability standards applicable to Pepco in the District of Columbia. The regulations establish specific maximum outage frequency and outage duration levels beginning in 2013 and continuing through 2020. The DCPSC has stated that the regulations are intended to require Pepco to achieve a reliability level in the first quartile of all utilities in the nation by 2020. The existing regulations of the DCPSC provide that Pepco would be subject to civil penalties or other sanctions if it does not meet the required performance levels. Pepco supports objective, fair reliability performance requirements, but believes that the regulations in their current form require inappropriate adjustments to the method employed to track reliability. Pepco filed a motion with the DCPSC seeking reconsideration of certain aspects of the regulations. There can be no assurance that the requested changes will be implemented or the timing related thereto. While Pepco is currently evaluating the cost and operational changes necessary to comply with the new requirements, Pepco currently believes the standards as adopted may not be realistically achievable at an acceptable cost over the longer term. Other jurisdictions in which PHI utilities have operations have reliability and customer service quality standards, the violation of which could also result in the imposition of penalties.

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

Operation of the Pepco, DPL and ACE transmission and distribution facilities and Pepco Energy Services’ generating facilities (scheduled for deactivation in May 2012) involves many risks, including the breakdown or failure of equipment, accidents, labor disputes and performance below expected levels. Older facilities and equipment, even if maintained in accordance with sound engineering practices, may require significant capital expenditures for additions or upgrades to provide reliable operations or to comply with changing environmental requirements. Natural disasters and weather, including tornadoes, hurricanes and snow and ice storms, also can disrupt transmission and distribution systems. Disruption of the operation of transmission or distribution facilities or the operation of generation facilities below expected output levels, can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance, including deficiency charges imposed by the PJM Interconnection, LLC (PJM) on generating facilities at a rate of up to two times the capacity payment that the generating facility receives. Furthermore, the transmission and generating facilities of the PHI companies are subject to reliability standards imposed by the North American Electric Reliability Corporation. Failure to comply with the standards may result in substantial monetary penalties.

PHI’s Blueprint for the Future program includes the replacement of customers’ existing electric and gas meters with an advanced metering infrastructure (AMI) system. In addition to the replacement of existing meters, the AMI system involves the construction of a wireless network across the service territories of PHI’s utility subsidiaries and the implementation and integration of new and existing information technology systems to collect and manage the data made available by the advanced meters. The implementation of the AMI system involves a combination of technologies provided by multiple vendors. If the AMI system results in lower than projected performance, PHI’s utility subsidiaries could experience higher than anticipated maintenance expenditures.

The Energy Services business of Pepco Energy Services is highly competitive. Under its energy savings performance contracts, Pepco Energy Services may be liable for performance guarantees many years after an installation of a project is completed. (PHI only)

The Energy Services business of Pepco Energy Services is highly competitive. This competition generally has the effect of limiting margins and requiring a continual focus on controlling costs.

Among the factors on which the Energy Services business competes are the amount and duration of the guarantees provided in energy savings performance contracts. In connection with many of its energy efficiency installation projects, Pepco Energy Services guarantees a minimum level of annual energy cost savings over a period typically ranging up to 15 years. Currently, Pepco Energy Services does not insure against this risk, and accordingly could suffer financial losses if a project does not achieve the guaranteed level of performance.

(2) The following risk factor supersedes, in its entirety, the risk factor in the 2010 Form 10-K with the heading, “Business operations could be adversely affected by terrorism.”

Business operations could be adversely affected by terrorism and cyber attacks.

The threat of, or actual acts of, terrorism may affect the operations of PHI and its subsidiaries in unpredictable ways and may cause changes in the insurance markets, force an increase in security measures and cause electrical disruptions or disruptions of fuel supplies and markets, including natural gas. If any of its infrastructure facilities, including its transmission or distribution facilities, were to be a direct target, or an indirect casualty, of an act of terrorism, the operations of PHI, Pepco, DPL or ACE could be adversely affected. Furthermore, any threats or actions that negatively impact the physical security of PHI’s and its subsidiaries’ facilities, or the integrity or security of their computer networks and

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systems (and any programs or data stored thereon or therein), could adversely affect PHI’s and its subsidiaries’ ability to manage these facilities, networks, systems, programs and data efficiently or effectively, which in turn could have a material adverse effect on our results of operations and financial condition. While PHI has implemented protective measures designed to mitigate physical and cyber attacks and their effects, there can be no assurance that such protective measures will be completely effective in protecting PHI’s infrastructure or assets from a physical or cyber attack or the effects thereof. Corresponding instability in the financial markets as a result of threats or acts of terrorism or cyber attacks also could adversely affect the ability of PHI or its subsidiaries to raise needed capital.

(3) Each of the following risk factors supplements the risk factors contained in each Reporting Company’s 2010 Form 10-K. Except as otherwise noted, each risk factor set forth below applies to each of PHI, Pepco, DPL and ACE.

The failure of PHI to obtain relief from the impact of “regulatory lag” may have a negative effect on PHI’s results of operations and financial condition.

The state public service commissions which regulate PHI’s public utility subsidiaries establish utility rates and tariffs intended to give each utility the opportunity to generate revenues sufficient to recover its costs, including a reasonable rate of return on investor supplied capital during the period the rates are in effect. The delay in recovering increased costs of distribution service is commonly known as “regulatory lag.” All of PHI’s utilities are currently experiencing significant regulatory lag, and PHI anticipates that this trend will continue for the foreseeable future.

In their most recent rate cases, Pepco (in the District of Columbia), DPL (in Maryland) and ACE (in New Jersey) have proposed mechanisms that would track reliability and other expenses and permit each utility to make adjustments in its approved rates to account for prudent investments as made, thereby seeking to reduce the magnitude of regulatory lag. To date, only the NJBPU has approved a similar mechanism, and other attempts made by PHI’s utility subsidiaries to obtain regulatory approval of measures to mitigate regulatory lag have been unsuccessful. There can be no assurance that continued efforts by PHI’s utility subsidiaries to mitigate regulatory lag in base rate cases or otherwise will be approved by the applicable public service commissions. If necessary to address in whole or in part the problem of regulatory lag, each utility would file rate cases at least annually to align its revenue and related cash flow levels allowed by the applicable public service commissions with other operation and maintenance spending and capital investments. The inability of PHI’s utility subsidiaries to obtain appropriate relief from the impact of regulatory lag may have an adverse effect on the results of operations and financial condition of PHI.

Further delays in the current in-service date for the MAPP project or the suspension or cancellation of this project would result in a reduction in PHI’s revenues. (PHI, Pepco and DPL)

In 2007, PJM directed PHI and its utility subsidiaries to construct MAPP to resolve future violations of national and regional standards for reliable operation of the region’s transmission system. Since that time, annual studies conducted by PJM have reaffirmed the need for MAPP; however, PJM’s latest analyses indicate that the projected need for MAPP has been delayed. As a result, on August 18, 2011, PJM notified PHI that the scheduled in-service date for MAPP has been delayed from June 1, 2015 to the 2019 to 2021 time period.

Until PJM’s evaluation is concluded, PJM directed PHI to limit further development efforts with respect to the MAPP project and to proceed with only those development efforts reasonably necessary to allow the MAPP project to be quickly restarted if and when deemed necessary. The delay of the in-service date would ultimately delay PHI’s ability to generate transmission revenue from the MAPP project, which is anticipated to generate higher rates of return on equity than other of PHI’s existing transmission assets. Furthermore, depending on the conclusions reached in its 2012 evaluation, PJM may further delay the required in-service date for the MAPP project or suspend or cancel the project altogether. Further delay,

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suspension or cancellation of the MAPP project may have an adverse effect on PHI’s business, results of operations, cash flows and financial condition.

Certain of PHI’s subsidiaries could be subject to penalties if they violate mandatory NERC reliability standards.

The Energy Policy Act of 2005 amended the Federal Power Act to, among other matters, provide for mandatory reliability standards designed to assure the reliable operation of the bulk power system. NERC established, and FERC approved, reliability standards that impose certain operating, planning and cyber security requirements on Pepco, DPL, ACE and Pepco Energy Services. NERC has delegated the day-to-day implementation and enforcement of its standards to eight regional oversight entities, including ReliabilityFirst Corporation (RFC), of which Pepco, DPL, ACE and Pepco Energy Services are members, and Northeast Power Coordinating Council (NPCC), of which Pepco Energy Services is a member.

RFC and NPCC perform compliance audits on entities registered with NERC based on reliability standards and criteria established by NERC. NERC, RFC and NPCC also conduct compliance investigations in response to a system disturbance, complaint, or possible violation of a reliability standard identified by other means. Pepco, DPL, ACE and Pepco Energy Services have been, and will continue to be, subject to routine audits and monitoring with respect to compliance with applicable NERC reliability standards, including standards requested by FERC to increase the number of assets (including cyber security assets) subject to NERC cyber security standards that are designated as “critical assets.” Pepco, DPL and ACE have settled certain issues with RFC related to such audits and monitoring. If any of PHI’s subsidiaries subject to NERC’s mandatory reliability standards are found to be in violation of those standards, such subsidiary could be subject to civil fines imposed by the enforcement entities, which could have a material adverse effect on a Reporting Company’s results of operations, cash flows and financial condition.

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. RESERVED

Item  5. OTHER INFORMATION

Pepco Holdings

None.

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Pepco

None.

DPL

None.

ACE

None.

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Item 6. EXHIBITS

The documents listed below are being filed, furnished or submitted on behalf of PHI, Pepco, DPL and/or ACE, as indicated. The warranties, representations and covenants contained in any of the agreements included or incorporated by reference herein or which appear as exhibits hereto should not be relied upon by buyers, sellers or holders of PHI’s or its subsidiaries’ securities and are not intended as warranties, representations or covenants to any individual or entity except as specifically set forth in such agreement.

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
3.1	PHI	Restated Certificate of Incorporation of Pepco Holdings, Inc. (as filed in Delaware)	Exhibit 3.1 to PHI’s Form 10-K, March 13, 2006.
3.2	Pepco	Restated Articles of Incorporation (as filed in the District of Columbia)	Exhibit 3.1 to Pepco’ Form 10-Q, May 5, 2006.
3.3	Pepco	Restated Articles of Incorporation and Articles of Restatement (as filed in Virginia)	Filed herewith.
3.4	DPL	Restated Certificate and Articles of Incorporation (as filed in Delaware and Virginia)	Exhibit 3.3 DPL’s Form 10-K, March 1, 2007.
3.5	ACE	Restated Certificate of Incorporation (as filed in New Jersey)	Exhibit B.8.1 to PHI’s Amendment No. 1 to Form U5B, February 13, 2003.
3.6	PHI	Bylaws	Exhibit 3 to PHI’s Form 8-K/A, May 3, 2007.
3.7	Pepco	By-Laws	Exhibit 3.2 to Pepco’s Form 10-Q, May 5, 2006.
3.8	DPL	Amended and Restated Bylaws	Exhibit 3.2.1 to DPL’s Form 10-Q May 9, 2005.
3.9	ACE	Amended and Restated Bylaws	Exhibit 3.2.2 to ACE’s Form 10-Q, May 9, 2005.
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.

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Exhibit No.	Registrant(s)	Description of Exhibit	Reference
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
101. INS	PHI, Pepco, DPL, ACE	XBRL Instance Document	Submitted herewith.
101. SCH	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Schema Document	Submitted herewith.
101. CAL	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Calculation Linkbase Document	Submitted herewith.
101. DEF	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Definition Linkbase Document	Submitted herewith.
101. LAB	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Label Linkbase Document	Submitted herewith.
101. PRE	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Presentation Linkbase Document	Submitted herewith.

Regulation S-K Item 10(d) requires registrants to identify the physical location, by SEC file number reference, of all documents incorporated by reference that are not included in a registration statement and have been on file with the SEC for more than five years. The SEC file number references for each Reporting Company are provided below:

Pepco Holdings, Inc. (File Nos. 001-31403 and 030-00359)

Potomac Electric Power Company (File No. 001-01072)

Delmarva Power & Light Company (File No. 001-01405)

Atlantic City Electric Company (File No. 001-03559)

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PEPCO HOLDINGS, INC. (PHI) POTOMAC ELECTRIC POWER COMPANY (Pepco) DELMARVA POWER & LIGHT COMPANY (DPL) ATLANTIC CITY ELECTRIC COMPANY (ACE) (Registrants)
November 4, 2011	By	/s/ ANTHONY J. KAMERICK
		Anthony J. Kamerick
		Senior Vice President and Chief Financial Officer, PHI,
		Pepco and DPL
		Chief Financial Officer, ACE

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INDEX TO EXHIBITS FILED HEREWITH OR INCORPORATED BY REFERENCE HEREIN

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
3.1	PHI	Restated Certificate of Incorporation of Pepco Holdings, Inc. (as filed in Delaware)	Exhibit 3.1 to PHI’s Form 10-K, March 13, 2006.
3.2	Pepco	Restated Articles of Incorporation (as filed in the District of Columbia)	Exhibit 3.1 to Pepco’s Form 10-Q, May 5, 2006.
3.3	Pepco	Restated Articles of Incorporation and Articles of Restatement (as filed in Virginia)	Filed herewith.
3.4	DPL	Restated Certificate and Articles of Incorporation (as filed in Delaware and Virginia)	Exhibit 3.3 to DPL’s Form 10-K, March 1, 2007.
3.5	ACE	Restated Certificate of Incorporation (as filed in New Jersey)	Filed herewith. Exhibit B.8.1 to PHI’s Amendment No. 1 to Form U5B, February 13, 2003.
3.6	PHI	Bylaws	Exhibit 3 to PHI’s Form 8-K/A, May 3, 2007.
3.7	Pepco	By-Laws	Exhibit 3.2 to Pepco’s Form 10-Q, May 5, 2006.
3.8	DPL	Amended and Restated Bylaws	Exhibit 3.2.1 to DPL’s Form 10-Q, May 9, 2005.
3.9	ACE	Amended and Restated Bylaws	Exhibit 3.2.2 to ACE’s Form 10-Q, May 9, 2005.
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.

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

INDEX TO EXHIBITS SUBMITTED HEREWITH
Exhibit No.	Registrant(s)	Description of Exhibit
101.INS	PHI, Pepco, DPL, ACE	XBRL Instance Document
101.SCH	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Schema Document
101.CAL	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	PHI, Pepco, DPL, ACE	XBRL Taxonomy Extension Presentation Linkbase Document