10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarter ended March 31, 2013

Commission File Number	Exact Name of Registrant as specified in its Charter, State or Other  Jurisdiction of Incorporation, Address of Principal Executive Offices, Zip Code and Telephone Number (Including Area Code)	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 ACE meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with reduced disclosure format specified in General Instruction H(2) of Form 10-Q.

Registrant	Number of Shares of Common Stock of the Registrant Outstanding at April 24, 2013
Pepco Holdings	248,581,877 ($.01 par value)
Pepco	100 ($.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		117
Item 3.	- Quantitative and Qualitative Disclosures About Market Risk		169
Item 4.	- Controls and Procedures		171
PART II	OTHER INFORMATION		171
Item 1.	- Legal Proceedings		171
Item 1A	- Risk Factors		172
Item 2.	- Unregistered Sales of Equity Securities and Use of Proceeds		174
Item 3.	- Defaults Upon Senior Securities		175
Item 4.	- Mine Safety Disclosures		175
Item 5.	- Other Information		175
Item 6.	- Exhibits		176
Signatures			179

GLOSSARY OF TERMS

Term	Definition
2012 Form 10-K	The Annual Report on Form 10-K for the year ended December 31, 2012 for each Reporting Company, as applicable
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
AMI	Advanced metering infrastructure
AOCL	Accumulated Other Comprehensive Loss
ASC	Accounting Standards Codification
BGE	Baltimore Gas and Electric Company
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
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
Contract EDCs	Pepco, DPL and BGE, the Maryland utilities required by the MPSC to enter into a contract for new generation
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
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
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
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
ISRA	New Jersey’s Industrial Site Recovery Act
LIBOR	London Interbank Offered Rate
LTIP	Pepco Holdings, Inc. Long-Term Incentive Plan
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.

i

Term	Definition
MFVRD	Modified fixed variable rate design
Mirant	Mirant Corporation
MPSC	Maryland Public Service Commission
MW	Megawatt
MWh	Megawatt hour
NJBPU	New Jersey Board of Public Utilities
NOAA	National Oceanic and Atmospheric Administration
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
RIM	Reliability investment recovery mechanism
ROE	Return on equity
RPS	Renewable Energy Portfolio Standards
SEC	Securities and Exchange Commission
SEPs	Supplemental Environmental Projects
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
SOS	Standard Offer Service, how Default Electricity Supply is referred to in Delaware, the District of Columbia and Maryland
SRECs	Solar renewable energy credits
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
VaR	Value at Risk

ii

FORWARD-LOOKING STATEMENTS

Some of the statements contained in this Quarterly Report on Form 10-Q with respect to Pepco Holdings, Inc. (PHI or Pepco Holdings), Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE), including each of their respective subsidiaries, 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 under the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding the intents, beliefs, estimates and current expectations of one or more of PHI, Pepco, DPL or ACE (each, a Reporting Company) or their subsidiaries. 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 Companies’ or their subsidiaries’ 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 or its subsidiaries’ 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 or one or more of the Reporting Companies specifically, 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;

• The outcome of pending and future rate cases and other regulatory proceedings, including (i) challenges to the base return on equity (ROE) and the application of the formula rate process for Pepco, DPL and ACE; (ii) challenges raised in Pepco’s and DPL’s Federal Energy Regulatory Commission (FERC) proceeding seeking, among other things, recovery of all prudently incurred Mid-Atlantic Power Pathway (MAPP) abandoned costs and the full ROE previously approved by FERC with respect to such costs; and (iii) the possible disallowance of other recovery of costs and expenses;

• The resolution of the cross-border lease matter, including the resolution of outstanding tax matters with the Internal Revenue Service (IRS), and the funding of any additional taxes, interest or penalties that may be due;

• The expenditures necessary to comply with regulatory requirements, including regulatory orders, and to implement reliability enhancement, emergency response and customer service improvement programs;

• Possible fines, penalties or other sanctions assessed by regulatory authorities against a Reporting Company or its subsidiaries;

• The impact of adverse publicity and media exposure which could render one or more Reporting Companies or their subsidiaries vulnerable to negative customer perception and could lead to increased regulatory oversight or other sanctions;

• 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;

1

• 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 (PJM), 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 or its subsidiaries’ 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 and other events, including the threat of domestic terrorism or cyber attacks.

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” and other statements in each Reporting Company’s annual report on Form 10-K for the year-ended December 31, 2012 (2012 Form 10-K), as filed with the Securities and Exchange Commission (SEC), and in this Form 10-Q, and investors should refer to such risk factors and other statements in evaluating the forward-looking statements contained in this Quarterly Report on Form 10-Q.

Any forward-looking statements speak only as to the date this Quarterly Report on Form 10-Q for each Reporting Company was filed with the SEC and none of the Reporting Companies undertakes an 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. Furthermore, it may not be possible to assess the impact of any such factor on such Reporting Company’s or its subsidiaries’ business (viewed independently or together with the business or businesses of some or all of the other Reporting Companies or their subsidiaries), 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 (Loss) Income		4		55		75		98
Consolidated Statements of Comprehensive (Loss) Income		5		N/A		N/A		N/A
Consolidated Balance Sheets		6		56		76		99
Consolidated Statements of Cash Flows		8		58		78		101
Consolidated Statement of Equity		9		59		79		102
Notes to Consolidated Financial Statements		10		60		80		103

* 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 (LOSS) INCOME

(Unaudited)

	Three Months Ended March 31,
	2013			2012
	(millions of dollars, except per share data)
Operating Revenue
Power Delivery	$	1,124		$	1,055
Pepco Energy Services		97			178
Other		(369	)		9
Total Operating Revenue		852			1,242
Operating Expenses
Fuel and purchased energy		600			641
Other services cost of sales		40			47
Other operation and maintenance		230			224
Depreciation and amortization		112			110
Other taxes		105			104
Deferred electric service costs		1			(15	)
Total Operating Expenses		1,088			1,111
Operating (Loss) Income		(236	)		131
Other Income (Expenses)
Interest expense		(67	)		(65	)
Other income		8			8
Total Other Expenses		(59	)		(57	)
(Loss) Income from Continuing Operations Before Income Tax Expense		(295	)		74
Income Tax Expense Related to Continuing Operations		135			11
Net (Loss) Income from Continuing Operations		(430	)		63
Income from Discontinued Operations, Net of Income Taxes		—			5
Net (Loss) Income	$	(430	)	$	68
Basic and Diluted Earnings per Share Information
Weighted average shares outstanding – Basic (millions)		237			228
Weighted average shares outstanding – Diluted (millions)		237			228
(Loss) earnings per share of common stock from Continuing
Operations – Basic and Diluted	$	(1.82	)	$	0.28
Earnings per share of common stock from Discontinued
Operations – Basic and Diluted		—			0.02
Basic and Diluted (loss) earnings per share	$	(1.82	)	$	0.30

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

4

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(Unaudited)

	Three Months Ended March 31,
	2013			2012
	(millions of dollars)
Net (Loss) Income	$	(430	)	$	68
Other Comprehensive Income from Continuing Operations
Losses on commodity derivatives designated as cash flow hedges reclassified into income		3			7
Pension and other postretirement benefit plans		2			1
Other comprehensive income, before income taxes		5			8
Income tax expense related to other comprehensive income		2			3
Other comprehensive income from continuing operations, net of income taxes		3			5
Other Comprehensive Income from Discontinued Operations, Net of Income Taxes		3			3
Comprehensive (Loss) Income	$	(424	)	$	76

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

5

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2013			December 31, 2012
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	125		$	25
Restricted cash equivalents		10			10
Accounts receivable, less allowance for uncollectible accounts of $39 million and $36 million, respectively		838			837
Inventories		153			155
Derivative assets		—			1
Prepayments of income taxes		50			59
Deferred income tax assets, net		36			28
Income taxes receivable		243			69
Prepaid expenses and other		66			76
Assets held for sale		—			1
Total Current Assets		1,521			1,261
INVESTMENTS AND OTHER ASSETS
Goodwill		1,407			1,407
Regulatory assets		2,566			2,614
Investment in finance leases held in trust		869			1,237
Income taxes receivable		51			217
Restricted cash equivalents		16			17
Assets and accrued interest related to uncertain tax positions		9			18
Derivative assets		8			8
Other		174			163
Total Investments and Other Assets		5,100			5,681
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		13,830			13,625
Accumulated depreciation		(4,796	)		(4,779	)
Net Property, Plant and Equipment		9,034			8,846
TOTAL ASSETS	$	15,655		$	15,788

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

6

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2013			December 31, 2012
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	1,041		$	965
Current portion of long-term debt and project funding		569			569
Accounts payable and accrued liabilities		486			574
Capital lease obligations due within one year		9			8
Taxes accrued		50			75
Interest accrued		84			47
Liabilities and accrued interest related to uncertain tax positions		379			9
Derivative liabilities		2			7
Other		256			273
Liabilities associated with assets held for sale		7			10
Total Current Liabilities		2,883			2,537
DEFERRED CREDITS
Regulatory liabilities		492			501
Deferred income taxes, net		2,685			3,176
Investment tax credits		20			20
Pension benefit obligation		388			449
Other postretirement benefit obligations		451			454
Liabilities and accrued interest related to uncertain tax positions		27			15
Derivative liabilities		11			11
Other		195			191
Liabilities associated with assets held for sale		1			2
Total Deferred Credits		4,270			4,819
LONG-TERM LIABILITIES
Long-term debt		3,898			3,648
Transition bonds issued by ACE Funding		246			256
Long-term project funding		11			12
Capital lease obligations		69			70
Total Long-Term Liabilities		4,224			3,986
COMMITMENTS AND CONTINGENCIES (NOTE 15)
EQUITY
Common stock, $.01 par value, 400,000,000 shares authorized, 248,551,381 and 230,015,427 shares outstanding, respectively		2			2
Premium on stock and other capital contributions		3,706			3,383
Accumulated other comprehensive loss		(42	)		(48	)
Retained earnings		612			1,109
Total Equity		4,278			4,446
TOTAL LIABILITIES AND EQUITY	$	15,655		$	15,788

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)

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
OPERATING ACTIVITIES
Net (loss) income	$	(430	)	$	68
Income from discontinued operations		—			(5	)
Adjustments to reconcile net (loss) income to net cash from operating activities:
Depreciation and amortization		112			110
Non-cash rents from cross-border energy lease investments		(5	)		(13	)
Non-cash charge to reduce carrying value of PHI’s cross-border energy lease investments		373			—
Deferred income taxes		(496	)		259
Other		(3	)		(5	)
Changes in:
Accounts receivable		(3	)		78
Inventories		3			—
Prepaid expenses		10			8
Regulatory assets and liabilities, net		(6	)		(37	)
Accounts payable and accrued liabilities		(63	)		(60	)
Pension contributions		(60	)		(200	)
Pension benefit obligation, excluding contributions		14			15
Cash collateral related to derivative activities		17			20
Income tax-related prepayments, receivables and payables		604			(247	)
Deposit made to taxing authority		(242	)		—
Interest accrued		37			33
Other assets and liabilities		(5	)		(2	)
Net assets held for sale		(3	)		1
Net Cash (Used By) From Operating Activities		(146	)		23
INVESTING ACTIVITIES
Investment in property, plant and equipment		(296	)		(291	)
Department of Energy capital reimbursement awards received		1			7
Changes in restricted cash equivalents		2			1
Net other investing activities		(3	)		2
Net Cash Used By Investing Activities		(296	)		(281	)
FINANCING ACTIVITIES
Dividends paid on common stock		(67	)		(61	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		15			17
Issuances of common stock		324			—
Issuances of long-term debt		250			—
Reacquisitions of long-term debt		(10	)		(9	)
Issuances of short-term debt, net		26			253
Issuance of term loan		250			—
Repayment of term loan		(200	)		—
Cost of issuances		(16	)		(3	)
Net other financing activities		(30	)		16
Net Cash From Financing Activities		542			213
Net Increase (Decrease) in Cash and Cash Equivalents		100			(45	)
Cash and Cash Equivalents at Beginning of Period		25			109
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	125		$	64
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes, net	$	(1	)	$	—

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

8

PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

	Common Stock					Premium on Stock			Accumulated Other Comprehensive (Loss) Income			Retained Earnings			Total
(millions of dollars, except shares)	Shares			Par Value
BALANCE, DECEMBER 31, 2012		230,015,427		$	2	$	3,383		$	(48	)	$	1,109		$	4,446
Net loss		—			—		—			—			(430	)		(430	)
Other comprehensive income		—			—		—			6			—			6
Dividends on common stock ($0.27 per share)		—			—		—			—			(67	)		(67	)
Issuance of common stock:
Original issue shares, net		18,268,100			—		321			—			—			321
Shareholder DRP original shares		370,787			—		8			—			—			8
Net activity related to stock-based awards		(102,933	)		—		(6	)		—			—			(6	)
BALANCE, MARCH 31, 2013		248,551,381		$	2	$	3,706		$	(42	)	$	612		$	4,278

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

9

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.

Each of PHI, Pepco, DPL and ACE is also a Reporting Company under the Securities Exchange Act of 1934, as amended. Together, Pepco, DPL and ACE constitute the Power Delivery segment, for financial reporting purposes.

Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy savings performance contracting services, high voltage underground transmission cabling, low voltage construction and maintenance services, and construction and operation of combined heat and power and central energy plants. Pepco Energy Services is in the process of winding down its competitive retail electric and natural gas 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 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

Each of Pepco, DPL and ACE is a regulated public utility 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 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 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 savings performance contracting 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 underground transmission construction and maintenance services to customers throughout the United States, as well as low voltage electric construction and maintenance services and streetlight construction services to utilities, municipalities and other customers in the Washington, D.C. metropolitan area, and

• providing retail customers electricity under its remaining contractual obligations.

During 2012, Pepco Energy Services deactivated its Buzzard Point oil-fired generation facility and its Benning Road oil-fired generation facility. Pepco Energy Services has placed the facilities into an idle condition termed a “Cold Closure.” A Cold Closure requires that the utility service be disconnected so that the facilities are no longer operable and that the facilities require only essential maintenance until they are completely decommissioned.

In December 2009, PHI announced the wind-down of the retail electric and natural gas supply components of the Pepco Energy Services business. Pepco Energy Services is implementing this wind-down by not entering into any new retail electric supply contracts while continuing to perform under its existing electric supply contracts through their respective expiration dates, the last of which is June 1, 2014. Also, as discussed below, on March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all of the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, gas inventory and derivative contracts. The transaction was completed on April 1, 2013.

The retail electric 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 electric supply business for the three months ended March 31, 2013 and 2012 were $41 million and $108 million, respectively, while operating income for the same periods was $1 million and $6 million, respectively.

In connection with the operation of the retail electric supply business, Pepco Energy Services provided letters of credit of less than $1 million and posted net cash collateral of $5 million as of March 31, 2013. These collateral requirements, which are based on existing wholesale electricity 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 savings services business will not be affected by the wind-down of the retail electric supply business.

Other Business Operations

Other Non-Regulated is a separate operating segment for financial reporting purposes and includes the portfolio of cross-border energy lease investments held through PHI’s subsidiary, Potomac Capital Investment Corporation (PCI). For a discussion of the Other Non- Regulated segment, see Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust,” Note (11), “Income Taxes,” and Note (15), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments.”

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Discontinued Operations

On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all of the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, gas inventory and derivative contracts. The transaction was completed on April 1, 2013. The operations of Pepco Energy Services’ retail natural gas supply business are being accounted for as a discontinued operation and are no longer a part of the Pepco Energy Services segment for financial reporting purposes. Substantially all of the information in these notes to the consolidated financial statements with respect to Pepco Energy Services’ retail natural gas supply business has been consolidated in Note (17), “Discontinued Operations.”

(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 consolidated financial statements prepared in accordance with GAAP have been omitted. Therefore, these consolidated financial statements should be read along with the annual consolidated financial statements included in PHI’s annual report on Form 10-K for the year ended December 31, 2012. 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 March 31, 2013, in accordance with GAAP. The year-end December 31, 2012 consolidated balance sheet included herein was derived from audited consolidated financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2013 may not be indicative of PHI’s results that will be realized for the full year ending December 31, 2013.

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 contingencies, future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefit assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto liability claims, accrual of interest related to income taxes, 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 (see Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust”), and income tax provisions and reserves. 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.

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Consolidation of Variable Interest Entities

PHI assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. Subsidiaries of PHI have the following contractual arrangements 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) totaling 459 megawatts (MWs). One of the agreements ends in 2016 and the other two end in 2024. PHI was unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, PHI 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 March 31, 2013 and 2012 were approximately $54 million and $51 million, respectively, of which approximately $54 million and $50 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. As of March 31, 2013, PHI, through its DPL subsidiary, is a party to three land-based wind PPAs in the aggregate amount of 128 MWs and one solar PPA with a 10 MW facility. Each of the facilities associated with these PPAs is operational, and DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and solar renewable energy credits (SRECs) from the solar facility up to certain amounts (as set forth below) at rates that are primarily fixed under the PPAs. PHI has concluded that consolidation is not required for any of these PPAs under the FASB guidance on the consolidation of variable interest entities.

DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs, in each case at the rates primarily fixed by the PPA. DPL’s purchases under the three wind PPAs totaled $10 million and $9 million for the three months ended March 31, 2013 and 2012, respectively.

The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. DPL’s purchases under the solar agreement were less than one million and zero for the three months ended March 31, 2013 and 2012, respectively.

On October 18, 2011, the Delaware Public Service Commission (DPSC) approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. 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 MW hour (MWh) of energy produced by the fuel cell facilities over 21 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 provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. In June 2012, a 3 MW fuel cell generation facility was placed into service under the tariff. DPL billed $3 million and zero to distribution customers for the three months ended March 31, 2013 and 2012, respectively. A 27 MW fuel cell generation facility is expected to be placed into service over time, with the first 5 MW increment having been placed into service at the end of 2012. DPL has concluded that consolidation under the variable interest entity consolidation guidance is not required for this arrangement.

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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 consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

ACE Standard Offer Capacity Agreements

In April 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 generation companies to receive payments from, or require them to 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 electric distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. ACE’s share of the payments received from or the payments made to the generation companies is currently estimated to be approximately 15 percent, based on its proportionate share of the total New Jersey electric load for all EDCs. The NJBPU has ordered that ACE is obligated to distribute to its distribution customers all payments it receives from the generation companies and may recover from its distribution customers all payments it makes to the generation companies. For additional discussion about the SOCAs, see Note (7), “Regulatory Matters.”

In May 2012, all three generation companies under the SOCAs bid into the PJM 2015-2016 capacity auction and two of the generators cleared that capacity auction. ACE recorded a derivative asset (liability) for the estimated fair value of each SOCA and recorded an offsetting regulatory liability (asset) as described in more detail in Note (13), “Derivative Instruments and Hedging Activities,” and Note (14), “Fair Value Disclosures.” FASB guidance on derivative accounting and the accounting for regulated operations would apply to ACE’s obligations under the third SOCA once the related capacity has cleared a PJM auction. The next PJM capacity auction is scheduled for May 2013. PHI has concluded that consolidation of the generation companies is not required.

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 (now Conectiv, LLC (Conectiv)) in 2002 and is allocated entirely to Power Delivery for purposes of impairment testing based on the aggregation of its components because its utilities have similar characteristics. 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 the carrying amount of its net assets. 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

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business conditions; a protracted decline in PHI’s stock price causing market capitalization to fall 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 March 31, 2013.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $84 million and $86 million for the three months ended March 31, 2013 and 2012, respectively.

Reclassifications

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

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Balance Sheet (ASC 210)

In December 2011, the FASB issued new disclosure requirements for financial assets and financial liabilities, such as derivatives, that are subject to contractual netting arrangements. The new disclosure requirements include information about the gross exposure of the instruments and the net exposure of the instruments under contractual netting arrangements, how the exposures are presented in the financial statements, and the terms and conditions of the contractual netting arrangements. As of March 31, 2013, PHI adopted the new guidance and concluded it did not have a material impact on its consolidated financial statements.

Comprehensive Income (ASC 220)

The new disclosure requirements for reclassifications from accumulated other comprehensive income were effective for PHI beginning with its March 31, 2013 consolidated financial statements and required PHI to present additional information about its reclassifications from accumulated other comprehensive income in a single footnote or on the face of its consolidated financial statements. The additional information required to be disclosed includes a presentation of the components of accumulated other comprehensive income that have been reclassified by source (e.g., commodity derivatives), and the income statement line item (e.g., Fuel and Purchased Energy) affected by the reclassification. PHI has provided the new required disclosures in Note (16), “Accumulated Other Comprehensive Loss.”

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Joint and Several Liability Arrangements (ASC 405)

In February 2013, the FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, PHI will be required to include in its liabilities the additional amounts it expects to pay on behalf of its co-obligors, if any. PHI will also be required to provide additional disclosures including the nature of the arrangements with its co-obligors, the total amounts outstanding under the arrangements between PHI and its co-obligors, the carrying value of the liability, and the nature and limitations of any recourse provisions that would enable recovery from other entities.

The new requirements would be effective retroactively beginning on January 1, 2014, with implementation required for prior periods if joint and several liability arrangement obligations exist as of January 1, 2014. PHI is evaluating the impact of this new guidance on its consolidated financial statements.

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(5) SEGMENT INFORMATION

Pepco Holdings’ management has identified its operating segments at March 31, 2013 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 months ended March 31, 2013 and 2012 is as follows:

	Three Months Ended March 31, 2013
	(millions of dollars)
	Power Delivery		Pepco Energy Services		Other Non- Regulated			Corporate and Other  (a)			PHI Consolidated
Operating Revenue	$	1,124	$	97	$	(368	)(b)	$	(1	)	$	852
Operating Expenses (c)		1,001		94		—			(7	)		1,088
Operating Income (Loss)		123		3		(368	)		6			(236	)
Interest Income		—		—		1			(1	)		—
Interest Expense		56		—		1			10			67
Other Income		6		1		1			—			8
Preferred Stock Dividends		—		—		1			(1	)		—
Income Tax Expense (d)		15		1		53	(e)		66			135
Net Income (Loss) from Continuing Operations		58		3		(421	)		(70	)		(430	)
Total Assets (excluding Assets Held For Sale)		12,453		368		882			1,952			15,655
Construction Expenditures	$	282	$	1	$	—		$	13		$	296

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. 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. Corporate and Other includes intercompany amounts of $(1) million for Operating Revenue, $(1) million for Operating Expenses, $(3) million for Interest Income, $(4) million for Interest Expense and $(1) million for Preferred Stock Dividends.

(b) Includes a non-cash pre-tax charge of $373 million to reduce the carrying value of the cross-border energy lease investments.

(c) Includes depreciation and amortization expense of $112 million, consisting of $104 million for Power Delivery, $2 million for Pepco Energy Services and $6 million for Corporate and Other.

(d) Includes after-tax interest associated with uncertain and effectively settled tax positions allocated to each member of the consolidated group, including a $12 million interest benefit for Power Delivery and interest expense of $16 million and $66 million for Other Non-Regulated and Corporate and Other, respectively.

(e) Includes non-cash charges of $64 million primarily for the tax consequences associated with PHI’s change in intent regarding foreign investment opportunities associated with the cross-border energy lease investments and $101 million representing the establishment of valuation allowances against certain deferred tax assets of PCI included in Other Non-Regulated.

	Three Months Ended March 31, 2012
	(millions of dollars)
	Power Delivery			Pepco Energy Services		Other Non- Regulated		Corporate and Other  (a)			PHI Consolidated
Operating Revenue	$	1,055		$	178	$	13	$	(4	)	$	1,242
Operating Expenses (b)		954			169		1		(13	)		1,111
Operating Income		101			9		12		9			131
Interest Income		—			—		1		(1	)		—
Interest Expense		53			1		3		8			65
Other Income (Expenses)		8			—		1		(1	)		8
Preferred Stock Dividends		—			—		1		(1	)		—
Income Tax Expense (Benefit)		9	(c)		3		—		(1	)		11
Net Income from Continuing Operations		47			5		10		1			63
Total Assets (excluding Assets Held For Sale)		11,473			583		1,487		1,684			15,227
Construction Expenditures	$	280		$	5	$	—	$	6		$	291

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. 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. Corporate and Other includes intercompany amounts of $(4) million for Operating Revenue, $(6) million for Operating Expenses, $(5) million for Interest Income, $(5) million for Interest Expense and $(1) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization expense of $110 million, consisting of $99 million for Power Delivery, $6 million for Pepco Energy Services, $1 million for Other Non-Regulated and $4 million for Corporate and Other.

(c) Includes income tax benefits of $10 million related to uncertain and effectively settled tax positions, primarily due to the effective settlement with the Internal Revenue Service with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position at Pepco.

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(6) GOODWILL

PHI’s goodwill balance of $1.4 billion was unchanged during the three months ended March 31, 2013. Substantially all of PHI’s goodwill balance 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, 2012 indicated that goodwill was not impaired. For the three months ended March 31, 2013, 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, 2013.

(7) REGULATORY MATTERS

Rate Proceedings

Over the last several years, PHI’s utility subsidiaries have proposed in each of their respective jurisdictions 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) was approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia.

• A modified fixed variable rate design (MFVRD) for DPL electric and natural gas service in Delaware is under consideration by the DPSC.

• In New Jersey, a BSA proposed by ACE in 2009 was not approved and there is no BSA proposal currently pending.

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 under consideration by the DPSC in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption of electricity or natural gas) 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.

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The following table shows, for each of the PHI utility subsidiaries, the current base rate cases filed. Please see the discussion below for more information concerning each of these filings.

Jurisdiction/Company	Current Requested Revenue Requirement Increase		Requested Return on Equity			Filing Date			Expected Timing of Decision
	(Millions of Dollars)
MD – Pepco Electric	$	60.8		10.25	%		11/30/12			Q3-2013
DE – DPL Gas		12.2		10.25	%		12/07/12			Q3-2013
NJ – ACE Electric		70.4		10.25	%		01/04/13	(a)		Q4-2013
DC – Pepco Electric		52.1		10.25	%		03/08/13			Q4-2013
DE – DPL Electric		42.0		10.25	%		03/22/13			Q4-2013
MD – DPL Electric		22.8		10.25	%		03/29/13			Q4-2013
Total	$	260.3

^(a) Filed 12/11/12; updated test period to 12 months actual data on 01/04/13.

Delaware

Gas Cost Rates

DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2012, DPL made its 2012 GCR filing. The rates proposed in the 2012 GCR would result in a GCR decrease of approximately 22.3%. On September 18, 2012, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2012, subject to refund and pending final DPSC approval. On April 24, 2013, DPL and the DPSC staff entered into a settlement agreement providing that the proposed GCR rates as filed by DPL should be approved. The settlement agreement is subject to DPSC approval. A DPSC decision on the settlement agreement is expected by the end of the third quarter of 2013.

Electric Distribution Base Rates

In December 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $31.8 million, based on a requested return on equity (ROE) of 10.75%, and requested approval of implementation of the MFVRD. In accordance with Delaware law and agreement with DPSC staff, DPL placed a total of $24.8 million of the requested rate increase into effect, subject to refund and pending final DPSC order. In November 2012, the DPSC approved a proposed settlement agreement entered into by DPL and the other parties to the proceeding that provided, among other things, for an annual rate increase of $22 million, based on an ROE of 9.75%. In February 2013, DPL refunded the billed amounts that exceeded the increase approved by the DPSC.

On March 22, 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $42 million, based on a requested ROE of 10.25%. The requested rate increase seeks to recover expenses associated with DPL’s ongoing efforts to maintain safe and reliable service. In accordance with Delaware law and because the DPSC suspended DPL’s full proposed increase, DPL plans to implement an interim increase of $2.5 million on June 1, 2013, subject to refund and pending final DPSC approval. A final DPSC decision is expected by the fourth quarter of 2013.

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Gas Distribution Base Rates

On December 7, 2012, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. The filing seeks approval of an annual rate increase of approximately $12.2 million, based on a requested ROE of 10.25%. The requested rate increase is for the purposes of recovering expenses associated with DPL’s ongoing efforts to maintain safe and reliable service and to provide enhanced customer service technology. In January 2013, the DPSC suspended the full proposed increase and, as permitted by state law, DPL implemented an interim increase of $2.5 million on February 5, 2013, subject to refund and pending final DPSC approval. A final DPSC decision is expected by the third quarter of 2013.

District of Columbia

On March 8, 2013, Pepco filed an application with the District of Columbia Public Service Commission (DCPSC) to increase its electric distribution base rates by approximately $52.1 million annually, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering (i) Pepco’s expenses associated with ongoing efforts to maintain safe and reliable service for its customers, (ii) Pepco’s investment in infrastructure to maintain and harden the electric distribution system, and (iii) Pepco’s major reliability enhancement improvements. A final DCPSC decision is expected by the fourth quarter of 2013.

Maryland

DPL Electric Distribution Base Rates

On March 29, 2013, DPL submitted an application with the MPSC to increase its electric distribution base rates by approximately $22.8 million, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering reliability enhancements to serve Maryland customers. DPL also proposes a three-year Grid Resiliency Charge rider for recovery of costs totaling approximately $10.2 million associated with its plan to accelerate investments in electric distribution infrastructure in a condensed timeframe. Acceleration of resiliency improvements is one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below). The Grid Resiliency Charge, if approved, would become effective January 1, 2014 and be implemented as a rider that is separate from base rates and would include a reasonable return on investment. Specific projects under DPL’s plan include accelerating its tree-trimming cycle and upgrading five additional feeders per year for two years. In addition, DPL proposes a reliability performance-based mechanism that would allow DPL to earn up to $500,000 as an incentive for meeting enhanced reliability goals in 2015, but provides a credit to customers of up to $500,000 in total if DPL does not meet at least the minimum reliability performance targets. DPL requests that any credits or charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the fourth quarter of 2013.

Pepco Electric Distribution Base Rates

In December 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently reduced by Pepco to $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorizes Pepco to recover the actual cost of advanced metering infrastructure (AMI) meters installed during the test year and states that cost recovery for AMI deployment will only be allowed in future rate cases in which Pepco demonstrates that the system is proven to be cost effective. The new revenue rates and lower depreciation rates were effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of installed AMI meters; that motion remains pending.

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On November 30, 2012, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $60.8 million, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering reliability enhancements to serve Maryland customers. Pepco also proposes a three-year Grid Resiliency Charge rider for recovery of costs totaling approximately $192 million associated with its plan to accelerate investments in infrastructure in a condensed timeframe. Acceleration of resiliency improvements is one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below). The Grid Resiliency Charge, if approved, would become effective January 1, 2014 and be implemented as a rider that is separate from base rates and would include a return on investment. Specific projects under Pepco’s plan include acceleration of its tree-trimming cycle, upgrade of 12 additional feeders per year for two years and undergrounding of six distribution feeders. In addition, Pepco proposes a reliability performance-based mechanism that would allow Pepco to earn up to $1 million as an incentive for meeting enhanced reliability goals in 2015, but provides a credit to customers of up to $1 million in total if Pepco does not meet at least the minimum reliability performance targets. Pepco requests that any credits/charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the third quarter of 2013.

New Jersey

Electric Distribution Base Rates

On December 11, 2012, ACE submitted an application with the NJBPU, updated on January 4, 2013, to increase its electric distribution base rates by approximately $70.4 million (excluding sales-and-use taxes), based on a requested ROE of 10.25%. This proposed net increase was comprised of (i) a proposed increase to ACE’s distribution rates of approximately $72.1 million and (ii) a net decrease to ACE’s Regulatory Asset Recovery Charge (costs associated with deferred, NJBPU-approved expenses incurred as part of ACE’s public service obligation) in the amount of approximately $1.7 million. The requested rate increase is primarily for the purposes of continuing to implement reliability-related investments and recovering system restoration costs associated with the June 2012 derecho storm and Hurricane Sandy. An NJBPU decision is expected by the fourth quarter of 2013.

In a March 20, 2013 order, the NJBPU established a generic proceeding to evaluate the prudency of major storm event restoration costs and expenses. Each New Jersey EDC was directed to file a separate proceeding for the evaluation of these costs. Those portions of ACE’s electric base rate filing pertaining to the recovery of major storm event expenditures will be evaluated in the context of the generic proceeding. On April 9, 2013, ACE filed a petition with the NJBPU to comply with the NJBPU’s generic storm cost order. All other issues in ACE’s base rate filing remain unchanged in the electric base rate proceeding discussed above.

Update and Reconciliation of Certain Under-Recovered Balances

In February 2012, ACE submitted a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program for low income customers) and ACE’s uncollected accounts and (iii) operating costs associated with ACE’s residential appliance cycling program. The filing proposed to recover the projected deferred under-recovered balance related to the NUGs of $113.8 million as of May 31, 2012 through a four-year amortization schedule. In June 2012, the NJBPU approved a stipulation of settlement signed by the parties, which provided for provisional rates that went into effect on July 1, 2012. The net impact of adjusting the charges (consisting of both the annual impact of the proposed four-year amortization of the historical under-recovered NUG balances of $127.0 million as of June 30, 2012 and the going-forward cost recovery of all the other charges for the period July 1, 2012 through May 31, 2013, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $55.3 million. The rates were deemed “provisional” because ACE’s filing was not updated for actual revenues and expenses for May and June 2012 until the March 5, 2013 petition described below was filed, after which a review by the NJBPU of the final underlying costs for reasonableness and prudence will be completed.

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On March 5, 2013, ACE submitted a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges for the New Jersey Societal Benefit Program and ACE’s uncollected accounts and (iii) operating costs associated with ACE’s residential appliance cycling program. The net impact of adjusting the charges updated for actual data through March 31, 2013 (consisting of both the second year impact of the stipulated four-year amortization of the historical under-recovered NUG balances and the going-forward cost recovery of all the other charges for the period June 1, 2013 through May 31, 2014, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $52.2 million. ACE expects that the final order in this proceeding will finalize the rates for the proceeding filed in February 2012. ACE has requested the NJBPU to issue a decision by the end of the second quarter of 2013.

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland 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.

In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 MW beginning in 2015. The order requires Pepco, DPL and Baltimore Gas and Electric Company (BGE) (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process in amounts proportional to their relative Standard Offer Service (SOS) loads. Under the contract, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015. The order acknowledged the Contract EDCs’ concerns about the requirements of the contract and directed them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specified that the Contract EDCs will recover the associated costs through surcharges on their respective SOS customers.

In April 2012, a group of generating companies operating in the PJM region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, the Contract EDCs and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These circuit court appeals were consolidated in the Circuit Court for Baltimore City and stayed pending the issuance of a final order from the MPSC approving the form of contract.

On April 16, 2013, the MPSC issued an order approving a final form of the contract and directing the Contract EDCs to enter into the contract, in amounts proportional to their relative SOS loads, with the winning bidder within 20 days of the order (i.e, by May 6, 2013). The MPSC stated that the order, which approves timely and complete recovery by the Contract EDCs of the costs associated with the contract, constitutes a binding commitment that shall not be subject to future modification or rescission by the MPSC. Despite this commitment from the MPSC, Pepco and DPL believe that the attempt by the MPSC to bind a future commission in this manner may be subject to legal challenge, which challenge, if successful, could impair the right of Pepco and DPL to recover their costs in the future. In addition, the MPSC excluded from the contract a provision that Pepco and DPL believe is important to mitigate their financial risk because the provision, had it been included, would have required Pepco and DPL to make payments to the winning bidder under the contract only to the extent they were able to recover those costs (for example, Pepco and DPL believe the excluded provision would have protected them in the event a significant number of their SOS customers elect to buy their energy from alternative energy suppliers). In light of the issuance of the MPSC’s final order, the previously filed appeals of the MPSC’s actions in this case before the circuit court will now proceed. Pepco and DPL anticipate that, in accordance with the terms of the MPSC’s order, they will enter into the contract within the 20-day period; however, under its own terms, the contract will not become effective, if at all, until all legal proceedings related to this contract or the actions of the MPSC in the related proceeding have been resolved.

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Until a final non-appealable court decision is rendered in connection with all such legal proceedings, PHI cannot predict (i) the extent of the negative effect that the contract for new generation may have on PHI’s, Pepco’s and DPL’s balance sheets, as well as their respective credit metrics, as calculated by independent rating agencies that evaluate and rate PHI, Pepco and DPL and each of their debt issuances, (ii) the effect on Pepco’s and DPL’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contract on the financial condition, results of operations and cash flows of each of PHI, Pepco and DPL.

Reliability Task Forces

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. Pepco’s electric distribution base rate case filed with the MPSC on November 30, 2012 and DPL’s electric distribution base rate case filed with the MPSC on March 29, 2013, each addresses the Grid Resiliency Task Force recommendations.

In August 2012, the District of Columbia mayor issued an Executive Order establishing the Mayor’s Power Line Undergrounding Task Force. The stated purpose of the Power Line Undergrounding Task Force is to pool the collective resources available in the District of Columbia to produce an analysis of the technical feasibility, infrastructure options and reliability implications of undergrounding new or existing overhead distribution facilities in the District of Columbia. These resources include legislative bodies, regulators, utility personnel, experts and other parties who could contribute in a meaningful way to the Power Line Undergrounding Task Force. The options that are available for financing these efforts are also to be evaluated to identify required legislative or regulatory actions to implement these recommendations. The results of this analysis are intended to help determine the path forward for these types of infrastructure improvements and additions. A written report from the Power Line Undergrounding Task Force setting forth the findings and recommendations was originally due on January 31, 2013 but the due date was extended to the second quarter of 2013.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company, as more fully described in Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – ACE Standard Offer Capacity Agreements” and Note (13), “Derivative Instruments and Hedging Activities.” ACE and the other New Jersey EDCs entered into the SOCAs under protest, arguing that the EDCs were denied due process and that the SOCAs violate certain of the requirements under the New Jersey law under which the SOCAs were established. The dispute is pending before the NJBPU and has been referred to an Administrative Law Judge for further consideration. On April 11, 2013, the Superior Court of New Jersey Appellate Division issued an order consolidating the EDCs’ state court appeal of the NJBPU order (filed by the EDCs with the Appellate Division of the New Jersey Superior Court in June 2011) with a similar challenge filed by several generators and instructing the Administrative Law Judge to complete proceedings by June 15, 2013. The matter remains pending.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the New Jersey law under which the SOCAs were established on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In September 2012, the District Court denied motions for summary judgment filed by ACE and the other plaintiffs, as well as cross-motions filed by defendants. The litigation remains pending and trial is scheduled to be completed on or before May 8, 2013. It has not been determined when the District Court will issue a decision.

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MAPP Project

On August 24, 2012, the board of PJM terminated the Mid-Atlantic Power Pathway (MAPP) project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. As of December 31, 2012, PHI’s total costs related to the MAPP project were $102 million. In a 2008 Federal Energy Regulatory Commission (FERC) order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, PHI submitted a filing to FERC seeking recovery of $88 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

Various protests were submitted in response to PHI’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of Pepco and DPL, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by PHI to be $2 million), of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. PHI believes that the FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that PHI is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. PHI cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, PHI had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories, for use on other projects, and reclassified the remaining $88 million of capital expenditures to a regulatory asset. During the first quarter of 2013, PHI further transferred an additional $2 million of materials to inventories, for use on other projects, and expensed $2 million of abandoned costs as a result of FERC’s disallowance noted above, resulting in a regulatory asset of $84 million as of March 31, 2013. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. PHI intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with FERC against Pepco, DPL and ACE, as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s utilities provide. The complainants claim to support an ROE within a zone of reasonableness of 6.78%

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and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. PHI, Pepco, DPL and ACE believe the allegations in this complaint are without merit and are vigorously contesting it. On April 3, 2013, Pepco, DPL and ACE filed their answer to this complaint, requesting that FERC dismiss the complaint against them on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

(8) LEASING ACTIVITIES

Investment in Finance Leases Held in Trust

Between 1994 and 2002, PCI entered into eight 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 of these lease investments is structured as a sale and leaseback transaction commonly referred to as a sale-in, lease-out, or SILO, transaction. Each lease investment is comprised of a number of leases. During the second quarter of 2011 and the third quarter of 2012, PHI entered into early termination agreements with several lessees comprising two of the eight lease investments and a small portion of the leases comprising a third lease investment. As of March 31, 2013 and December 31, 2012, the lease portfolio consisted of six investments with a net investment value of $869 million and $1,237 million, respectively.

The components of the cross-border energy lease investments as of March 31, 2013 and December 31, 2012 are summarized below:

	March 31, 2013			December 31, 2012
	(millions of dollars)
Scheduled lease payments to PHI, net of non-recourse debt	$	1,842		$	1,852
Less: Unearned and deferred income		(973	)		(615	)
Investment in finance leases held in trust		869			1,237
Less: Deferred income tax liabilities		(95	)		(756	)
Net investment in finance leases held in trust	$	774		$	481

Income recognized from cross-border energy lease investments was comprised of the following for the three months ended March 31, 2013 and 2012:

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
Pre-tax income from PHI’s cross-border energy lease investments (included in Other Revenue)	$	5		$	13
Non-cash charge to reduce carrying value of PHI’s cross-border energy lease investments		(373	)		—
Pre-tax (loss) income from PHI’s cross-border energy lease investments after adjustment		(368	)		13
Income tax (benefit) expense related to PHI’s cross-border energy lease investments, including interest expense on uncertain tax positions of $16 million		(48	)		1
Net (loss) income from PHI’s cross-border energy lease investments	$	(320	)	$	12

PHI is required to assess on a periodic basis the likely outcome of tax positions relating to its cross-border energy lease investments and, if there is a change or a projected change in the timing of the estimated tax benefits generated by the transactions, PHI is required to recalculate the value of its net investment.

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On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that its tax position with respect to the benefits associated with its cross-border energy leases no longer meets the more likely than not standard of recognition for accounting purposes, and PHI recorded an after-tax non-cash charge of $377 million in the first quarter of 2013, consisting of the following components:

• A non-cash pre-tax charge of $373 million ($307 million after-tax) to reduce the carrying value of these cross-border energy lease investments under FASB guidance on leases (ASC 840). This pre-tax charge has been recorded in the consolidated statement of income as a reduction in Other Operating revenue.

• A non-cash charge of $70 million after-tax to reflect the anticipated additional net interest expense under FASB guidance for income taxes (ASC 740), related to estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed. This after-tax charge has been recorded in the consolidated statement of income as an increase in income tax expense and was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in the recognition of a $12 million interest benefit for the Power Delivery segment and interest expense of $16 million and $66 million for the Other Non-Regulated and Corporate and Other segments, respectively.

PHI had also previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. In view of the change in PHI’s tax position with respect to the tax benefits associated with the cross-border energy lease investments and PHI’s resulting decision to pursue the early termination of these investments, management has concluded that these business assumptions are no longer supportable and the tax effects of this conclusion are reflected in the after-tax charge of $307 million described above.

PHI has accrued no penalties associated with its re-assessment of the likely outcome of tax positions associated with the cross-border energy lease investments. While the Internal Revenue Service (IRS) could require PHI to pay a penalty of up to 20% of the amount of additional taxes due, PHI believes that it is more likely than not that no such penalty will be incurred, and therefore no amount for any potential penalty was included in the charge.

In March 2013, PHI began to pursue the early termination of its remaining cross-border energy lease investments with its lessees. During April 2013, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the six lease investments and one of the leases included in a second lease investment. Upon closing, PHI received aggregate net cash proceeds of $168 million (net of aggregate termination payments of $804 million used to retire the non-recourse debt associated with the terminated leases) and expects to record a net pre-tax loss of approximately $27 million in the second quarter of 2013, representing the excess of the carrying value of the terminated leases over the net cash proceeds received. PHI estimates that the early termination of the remaining cross-border energy lease investments could be accomplished during 2013. The aggregate financial impact of the early termination of the remaining cross-border energy lease investments is not determinable at this time, but management believes that any gains or losses incurred in the aggregate will not be material; however, there may be individual lease terminations that result in offsetting material gains and losses.

For additional information concerning these cross-border energy lease investments, see Note (15), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments.”

To ensure credit quality, PHI regularly monitors the financial performance and condition of the lessees under its cross-border energy lease investments. Changes in credit quality are also assessed to determine if they should be reflected in the carrying value of the leases. PHI compares each lessee’s performance to annual compliance requirements set by the terms and conditions of the leases. This includes a comparison of

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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 their company and asset performance. If the annual compliance requirements or minimum credit ratings are not met, remedies are available under the leases. At March 31, 2013, all lessees were in compliance with the terms and conditions of their lease agreements.

The table below shows PHI’s net investment in these leases by the published credit ratings of the lessees as of March 31, 2013 and December 31, 2012:

Lessee Rating (a)	March 31, 2013		December 31, 2012
	(millions of dollars)
Rated Entities
AA/Aa and above	$	537	$	766
A		332		471
Total	$	869	$	1,237

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

(9) PENSION AND OTHER POSTRETIREMENT BENEFITS

The following Pepco Holdings information is for the three months ended March 31, 2013 and 2012:

	Pension Benefits						Other Postretirement Benefits
	2013			2012			2013			2012
	(millions of dollars)
Service cost	$	13		$	11		$	2		$	1
Interest cost		25			26			8			9
Expected return on plan assets		(37	)		(34	)		(5	)		(5	)
Amortization of prior service cost		—			—			(1	)		(1	)
Amortization of net actuarial loss		16			14			4			5
Net periodic benefit cost	$	17		$	17		$	8		$	9

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. 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 target liability as defined under the Pension Protection Act of 2006. In the first quarter of 2013, PHI, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $20 million, $10 million and $30 million, respectively. In the first quarter of 2012, Pepco, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $85 million, $85 million and $30 million, respectively, which brought the PHI Retirement Plan assets to the funding target level for 2012 under the Pension Protection Act.

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(10) DEBT

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement, which among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility.

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 is $750 million for PHI 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 the one month London Interbank Offered Rate 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 and other 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) with certain exceptions, a restriction on sales or other dispositions of assets, 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 credit agreement contains certain covenants and other customary agreements and requirements that, if not 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 covenants under this facility as of March 31, 2013.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

At March 31, 2013 and December 31, 2012, the amount of cash plus unused borrowing capacity under the credit facility available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $975 million and $861 million, respectively. PHI’s utility subsidiaries had combined cash and unused borrowing capacity under the credit facility of $635 million and $477 million at March 31, 2013 and December 31, 2012, respectively.

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Commercial Paper

PHI, Pepco, DPL and ACE maintain on-going commercial paper programs to address short-term liquidity needs. As of March 31, 2013, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $250 million, respectively, subject to available borrowing capacity under the credit facility.

PHI, DPL and ACE had $408 million, $70 million and $185 million, respectively, of commercial paper outstanding at March 31, 2013. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during the three months ended March 31, 2013 was 0.76%, 0.38%, 0.36% and 0.37%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during the three months ended March 31, 2013 was ten, seven, three and seven days, respectively.

Other Financing Activities

Term Loan Agreement

On March 28, 2013, PHI entered into a $250 million term loan agreement, pursuant to which PHI has borrowed (and may not re-borrow) $250 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the London Interbank Offered Rate (LIBOR) with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.875%. PHI’s Eurodollar borrowings under the loan agreement may be converted into floating rate loans under certain circumstances, and, in that event, for so long as any loan remains a floating rate loan, interest would accrue on that loan at a rate per year equal to (i) the highest of (a) the prevailing prime rate, (b) the federal funds effective rate plus 0.5%, or (c) the one-month Eurodollar rate plus 1%, plus (ii) a margin of 0.875%. As of March 31, 2013, outstanding borrowings under the loan agreement bore interest at an annual rate of 1.09%, which is subject to adjustment from time to time. All borrowings under the loan agreement are unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before March 27, 2014. PHI used the net proceeds of the loan under the loan agreement to repay the outstanding $200 million term loan made in 2012, and for general corporate purposes.

Under the terms of the term loan agreement, PHI must maintain compliance with specified covenants, including (i) the requirement that PHI maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the loan 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 permitted sales and dispositions, and (iii) a restriction on the incurrence of liens (other than liens permitted by the loan agreement) on the assets of PHI or any of its significant subsidiaries. The loan agreement does not include any rating triggers. PHI was in compliance with all covenants under this agreement as of March 31, 2013.

Bond Issuances

In March 2013, Pepco issued $250 million of 4.15% first mortgage bonds due March 15, 2043. These bonds were issued under a Mortgage and Deed of Trust and are secured thereunder by a first lien, subject to certain leases, permitted liens and other exceptions, on substantially all of Pepco’s properties. Net proceeds from the issuance of the long-term debt were used to repay Pepco’s outstanding commercial paper that was issued to temporarily fund capital expenditures, provide working capital and for general corporate purposes.

Bond Payments

In January 2013, ACE Funding made principal payments of $7 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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Financing Activities Subsequent to March 31, 2013

Bond Payments

In April 2013, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

Bond Redemptions

In April 2013, ACE issued notice for optional redemption on May 30, 2013, at par plus accrued interest, of all $4.4 million outstanding weekly rate pollution control revenue refunding bonds due 2017, issued by the Pollution Control Financing Authority of Salem County, New Jersey for ACE’s benefit.

Collateral Requirements of Pepco Energy Services

In the ordinary course of its energy supply business, which is in the process of being wound down, Pepco Energy Services entered 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.

As of March 31, 2013, Pepco Energy Services had posted net cash collateral of $5 million and letters of credit of less than $1 million associated with its retail electric supply business. At December 31, 2012, Pepco Energy Services had posted net cash collateral of $14 million and letters of credit of less than $1 million associated with its retail electric supply business.

At March 31, 2013 and December 31, 2012, the amount of cash, plus borrowing capacity under PHI’s credit facility available to meet the future liquidity needs of Pepco Energy Services, totaled $340 million and $384 million, respectively.

(11) INCOME TAXES

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

	Three Months Ended March 31,
	2013					2012
	(millions of dollars)
Income tax at Federal statutory rate	$	(103	)	35.0	%	$	26		35.0	%
Increases (decreases) resulting from:
State income taxes, net of Federal effect		5		(1.7	)%		4		5.4	%
Asset removal costs		(3	)	1.0	%		(3	)	(4.1	)%
Changes in estimates and interest related to uncertain and effectively settled tax positions		67		(22.7	)%		(13	)	(17.6	)%
Cross-border energy lease investments		64		(21.7	)%		(1	)	(1.4	)%
Establishment of valuation allowances related to deferred tax assets		101		(34.2	)%		—		—
Other, net		4		(1.5	)%		(2	)	(2.4	)%
Consolidated income tax expense related to continuing operations	$	135		(45.8	)%	$	11		14.9	%

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PHI’s consolidated effective tax rates for the three months ended March 31, 2013 and 2012 were (45.8)% and 14.9%, respectively.

The negative effective tax rate in the first quarter of 2013 occurred as a result of recording $67 million of changes in estimates and interest related to uncertain and effectively settled tax positions, primarily associated with the cross-border energy lease investments (as further discussed in Note (8), “Leasing Activities”) and the recognition of a $64 million charge primarily for the tax consequences associated with PHI’s change in intent regarding foreign investment opportunities available at the end of the full lease terms of the cross-border energy lease investments.

The negative effective tax rate in the first quarter of 2013 further resulted from the establishment of valuation allowances of $101 million against certain deferred tax assets in PHI’s Other Non-Regulated segment. Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to both Consolidated Edison’s cross-border lease transaction (as discussed in Note (8), “Leasing Activities”) and another taxpayer’s structured transactions, (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represents a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI will be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI has established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013.

In 2012, PHI’s effective tax rate was impacted by the effective settlement with the IRS in the first quarter of 2012 with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position in Pepco.

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(12) EQUITY AND EARNINGS PER SHARE

Basic and Diluted Earnings Per Share

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

	Three Months Ended March 31,
	2013			2012
	(millions of dollars, except per share data)
Income (Numerator):
Net (Loss) Income from continuing operations	$	(430	)	$	63
Net (Loss) Income from discontinued operations		—			5
Net (Loss) Income	$	(430	)	$	68
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		237			228
Adjustment to shares outstanding		—			—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		237			228
Net effect of potentially dilutive shares (a)		—			—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		237			228
Basic and Diluted Earnings per Share
(Loss) Earnings per share of common stock from continuing operations	$	(1.82	)	$	0.28
Earnings per share of common stock from discontinued operations		—			0.02
Basic and diluted (loss) earnings per share	$	(1.82	)	$	0.30

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS as they are considered to be anti-dilutive were zero and 3,000 for the three months ended March 31, 2013 and 2012, respectively.

Equity Forward Transaction

During 2012, PHI entered into an equity forward transaction in connection with a public offering of PHI common stock. Pursuant to the terms of this transaction, a forward counterparty borrowed 17,922,077 shares of PHI’s common stock from third parties and sold them to a group of underwriters for $19.25 per share, less an underwriting discount equal to $0.67375 per share. Under the terms of the equity forward transaction, upon physical settlement thereof, PHI was required to issue and deliver the shares of PHI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $18.57625 per share at the time the equity forward transaction was entered into and was subject to reduction from time to time in accordance with the terms of the equity forward transaction. On February 27, 2013, PHI physically settled the equity forward at the then applicable forward sale price of $17.39. The proceeds of approximately $312 million were used to repay outstanding commercial paper, a portion of which had been issued in order to make capital contributions to the utilities, and for general corporate purposes.

Treasury Stock

Premium on stock and other capital contributions on PHI’s consolidated balance sheet at March 31, 2013 includes approximately $2 million of treasury stock outstanding, representing 102,933 shares with a weighted-average price of $19.93. These shares were repurchased during the first quarter of 2013 to cover minimum withholding taxes of certain participants in PHI’s Long-Term Incentive Plan.

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(13) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

The retail electric 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 futures, swaps, options and forward contracts to hedge commodity price risk in connection with the purchase of physical 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 Power Delivery, 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 uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. 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.

ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would receive payments from or make payments to electric generation facilities based on i) the difference between the fixed price in the SOCAs and the price for capacity that clears PJM and ii) ACE’s annual proportion of the total New Jersey load relative to the other EDCs in New Jersey, which is currently estimated to be approximately 15 percent. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because the generators cleared the 2015-2016 PJM capacity auction in May 2012. Changes in the fair value of the derivatives embedded in the SOCAs are deferred as Regulatory Assets or Regulatory Liabilities because the NJBPU has allowed full recovery from ACE’s distribution customers for all payments made by ACE, and ACE’s distribution customers would be entitled to all payments received by ACE.

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 its 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 Accumulated Other Comprehensive Loss (AOCL) and is being recognized in income over the life of the debt issued as interest payments are made.

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The tables below identify the balance sheet location and fair values of derivative instruments as of March 31, 2013 and December 31, 2012:

	As of March 31, 2013
Balance Sheet Caption	Derivatives Designated as Hedging Instruments (a)			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative assets (current assets)	$	—		$	1		$	1		$	(1	)	$	—
Derivative assets (non-current assets)		—			8			8			—			8
Total Derivative assets		—			9			9			(1	)		8
Derivative liabilities (current liabilities)		(2	)		(2	)		(4	)		2			(2	)
Derivative liabilities (non-current liabilities)		—			(11	)		(11	)		—			(11	)
Total Derivative liabilities		(2	)		(13	)		(15	)		2			(13	)
Net Derivative (liability) asset	$	(2	)	$	(4	)	$	(6	)	$	1		$	(5	)

(a) Amounts included in Derivatives Designated as Hedging Instruments primarily consist of derivatives that were designated as cash flow hedges prior to Pepco Energy Services’ election to discontinue cash flow hedge accounting for these derivatives.

	As of December 31, 2012
Balance Sheet Caption	Derivatives Designated as Hedging Instruments (a)			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative assets (current assets)	$	—		$	1		$	1		$	—	$	1
Derivative assets (non-current assets)		—			8			8			—		8
Total Derivative assets		—			9			9			—		9
Derivative liabilities (current liabilities)		(5	)		(8	)		(13	)		6		(7	)
Derivative liabilities (non-current liabilities)		—			(11	)		(11	)		—		(11	)
Total Derivative liabilities		(5	)		(19	)		(24	)		6		(18	)
Net Derivative (liability) asset	$	(5	)	$	(10	)	$	(15	)	$	6	$	(9	)

(a) Amounts included in Derivatives Designated as Hedging Instruments primarily consist of derivatives that were designated as cash flow hedges prior to Pepco Energy Services’ election to discontinue cash flow hedge accounting for these derivatives.

Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), PHI offsets the fair value amounts recognized for derivative assets and liabilities and the fair value amounts recognized for related collateral positions executed with the same counterparty under master netting agreements. All derivative assets and liabilities available to be offset under master netting arrangements were netted as of March 31, 2013 and December 31, 2012. The amount of cash collateral that was offset against these derivative positions is as follows:

	March 31, 2013			December 31, 2012
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	2		$	6
Cash collateral received from counterparties with the obligation to return		(1	)		—

(a) Includes cash deposits on commodity brokerage accounts.

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As of March 31, 2013 and December 31, 2012, all PHI 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

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. The retail electric business of Pepco Energy Services does not apply cash flow hedge accounting to certain of its electricity derivatives. Amounts included in AOCL for these cash flow hedges as of March 31, 2013 and 2012 represent net losses on derivatives prior to the election to discontinue cash flow hedge accounting less amounts reclassified into income as the hedged transactions occur or because the hedged transactions were deemed probable not to occur. Gains or losses on these derivatives after the election to discontinue cash flow hedge accounting are recognized in income.

The cash flow hedge activity during the three months ended March 31, 2013 and 2012 is provided in the tables below:

	Three Months Ended March 31,
	2013		2012
	(millions of dollars)
Amount of net pre-tax loss arising during the period included in Accumulated Other Comprehensive Loss	$	—	$	—
Amount of net pre-tax loss reclassified into income:
Effective portion:
Fuel and Purchased Energy expense		3		7
Ineffective portion: (a)
Revenue		—		—
Total net pre-tax loss reclassified into income		3		7
Net pre-tax gain on commodity derivatives included in Accumulated Other Comprehensive Loss	$	3	$	7

(a) For the three months ended March 31, 2013 and 2012, no amounts were reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur.

As of March 31, 2013 and December 31, 2012, the retail electric business of Pepco Energy Services had no outstanding energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.

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 sheets as of March 31, 2013 and 2012. Cash flow hedges are marked to market on the consolidated balance sheet with corresponding adjustments to AOCL for effective cash flow hedges. As of March 31, 2013 and 2012, $2 million and $16 million, respectively, of the losses in AOCL were associated with derivatives that the retail electric business of Pepco Energy Services previously designated as cash flow hedges. Although the retail electric business of Pepco Energy Services no longer designates these derivatives as cash flow hedges, gains or losses previously deferred in AOCL prior to the decision to discontinue cash flow hedge accounting will remain in AOCL until the hedged forecasted transaction occurs unless it is deemed probable that the

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hedged forecasted transaction will not occur. The data in the following 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:

Contracts	As of March 31, 2013				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Energy commodity (a)	$	1	$	1		2 months
Interest rate		10		1		233 months
Total	$	11	$	2

(a) The unrealized derivative losses recorded in AOCL relate to forecasted physical electricity purchases which are used to supply retail electricity contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on PHI’s consolidated balance sheet for the retail contracts and the purchase cost is not recognized until the period of distribution.

Contracts	As of March 31, 2012				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Energy commodity (a)	$	11	$	10		14 months
Interest rate		10		1		245 months
Total	$	21	$	11

(a) The unrealized derivative losses recorded in AOCL relate to forecasted physical and electricity purchases which are used to supply retail electricity contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on PHI’s consolidated balance sheet for the retail contracts and the purchase cost is not recognized until the period of distribution.

Other Derivative Activity

Pepco Energy Services

The retail electric business of Pepco Energy Services holds certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the balance sheet with the gain or loss for changes in fair value recorded through Fuel and Purchased Energy expense.

For the three months ended March 31, 2013 and 2012, the amount of the derivative gain (loss) for the retail electric business of Pepco Energy Services recognized in income is provided in the table below:

	Three Months Ended March  31,
	2013		2012
	(millions of dollars)
Reclassification of mark-to-market to realized on settlement of contracts	$	2	$	2
Unrealized mark-to-market loss		—		(4	)
Total net gain (loss)	$	2	$	(2	)

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As of March 31, 2013 and December 31, 2012, the retail electric business of Pepco Energy Services had the following net outstanding commodity forward contract quantities and net position on derivatives that did not qualify for hedge accounting:

	March 31, 2013				December 31, 2012
Commodity	Quantity		Net Position		Quantity		Net Position
Financial transmission rights (MWh)		86,746		Long		181,008		Long
Electricity (MWh)		131,640		Long		261,240		Long

Power Delivery

DPL and ACE have certain derivatives that are not in hedge accounting relationships and are not 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 changes 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 DPL’s derivatives and the NJBPU order pertaining to the SOCAs within which ACE’s capacity derivatives are embedded. The following table indicates the net unrealized derivative gains and losses arising during the period that were deferred as Regulatory Liabilities and Regulatory Assets, respectively, and the net realized losses recognized in the consolidated statements of income (through Fuel and Purchased Energy expense) that were also deferred as Regulatory Assets for the three months ended March 31, 2013 and 2012 associated with these derivatives:

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
Net unrealized gain (loss) arising during the period	$	2		$	(4	)
Net realized loss recognized during the period		(4	)		(7	)

As of March 31, 2013 and December 31, 2012, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts and ACE’s capacity derivatives associated with the SOCAs that did not qualify for hedge accounting were:

	March 31, 2013				December 31, 2012
Commodity	Quantity		Net Position		Quantity		Net Position
DPL – Natural gas (one Million British Thermal Units (MMBtu))		3,245,000		Long		3,838,000		Long
ACE – Capacity (MWs)		180		Long		180		Long

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Contingent Credit Risk Features

The primary contracts used by the retail electric business of Pepco Energy Services and the Power Delivery segment 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 the retail electric business 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 debt 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 values of PHI’s derivative liabilities with credit risk-related contingent features as of March 31, 2013 and December 31, 2012, were $2 million and $8 million, respectively, before giving effect to offsetting transactions or collateral under master netting agreements. As of March 31, 2013 and December 31, 2012, PHI had posted no cash collateral against its gross derivative liability, resulting in a net liability of $2 million and $8 million, respectively. If PHI’s and DPL’s debt ratings had been downgraded below investment grade as of March 31, 2013 and December 31, 2012, PHI’s net settlement amounts, including both the fair value of its derivative liabilities and its normal purchase and normal sale contracts would have been approximately $24 million and $40 million, respectively, and PHI would have been required to post collateral with the counterparties of approximately $24 million and $40 million, respectively, in addition to that which was posted as of March 31, 2013 and December 31, 2012. The net settlement and additional collateral amounts reflect the effect of offsetting transactions under master netting agreements.

PHI’s primary source for posting cash collateral or letters of credit is its credit facility. At March 31, 2013 and December 31, 2012, the aggregate amount of cash plus borrowing capacity under the credit facility available to meet the future liquidity needs of PHI and its subsidiaries totaled $975 million and $861 million, respectively, of which $340 million and $384 million, respectively, was available to the retail electric business of Pepco Energy Services.

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(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).

The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2013 and December 31, 2012. 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.

	Fair Value Measurements at March 31, 2013
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)
Natural gas (d)	$	1	$	1	$	—	$	—
Capacity (e)		8		—		—		8
Cash equivalents
Treasury fund		112		112		—		—
Executive deferred compensation plan assets
Money market funds		17		17		—		—
Life insurance contracts		62		—		43		19
	$	200	$	130	$	43	$	27
LIABILITIES
Derivative instruments (b)
Electricity (c)	$	4	$	—	$	4	$	—
Capacity (e)		11		—		—		11
Executive deferred compensation plan liabilities
Life insurance contracts		29		—		29		—
	$	44	$	—	$	33	$	11

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.

(b) The fair values 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 electric supply business.

(d) Represents natural gas swaps purchased by DPL as part of a natural gas hedging program approved by the DPSC.

(e) Represents derivatives associated with ACE SOCAs.

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	Fair Value Measurements at December 31, 2012
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)	$	1	$	—	$	1	$	—
Capacity (e)		8		—		—		8
Cash equivalents
Treasury fund		27		27		—		—
Executive deferred compensation plan assets
Money market funds		17		17		—		—
Life insurance contracts		60		—		42		18
	$	113	$	44	$	43	$	26
LIABILITIES
Derivative instruments (b)
Electricity (c)	$	10	$	—	$	10	$	—
Natural gas (d)		4		—		—		4
Capacity (e)		11		—		—		11
Executive deferred compensation plan liabilities
Life insurance contracts		28		—		28		—
	$	53	$	—	$	38	$	15

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.

(b) The fair values 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 electric supply business.

(d) Represents natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

(e) Represents derivatives associated with ACE SOCAs.

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).

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 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 March 31, 2013. Level 2 power swaps are provided by a pricing service that uses liquid trading hub prices or liquid hub prices plus a congestion adder to estimate the fair value at zonal locations within trading hubs.

Executive deferred compensation plan assets consist of life insurance policies and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued 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 and can be liquidated for the value of the underlying

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assets as of March 31, 2013. 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.

The value of certain employment agreement obligations is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data.

Level 3 – Pricing inputs that are significant and 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 used by DPL as part of a natural gas hedging program approved by the DPSC and capacity under the SOCAs entered into by ACE:

• DPL applies a Black-Scholes model to value its options with inputs, such as forward price curves, contract prices, contract volumes, the risk-free rate and implied volatility factors, that are based on a range of historical NYMEX option prices. DPL maintains valuation policies and procedures and reviews the validity and relevance of the inputs used to estimate the fair value of its options. As of March 31, 2013, all of these contracts classified as level 3 derivative instruments have settled.

• ACE used a discounted cash flow methodology to estimate the fair value of the capacity derivatives embedded in the SOCAs. ACE utilized an external valuation specialist to estimate annual zonal PJM capacity prices through the 2030-2031 auction. The capacity price forecast was based on various assumptions that impact the cost of constructing new generation facilities, including zonal load forecasts, zonal fuel and energy prices, generation capacity and transmission planning, and environmental legislation and regulation. ACE reviewed the assumptions and resulting capacity price forecast for reasonableness. ACE used the capacity price forecast to estimate future cash flows. A significant change in the forecasted prices would have a significant impact on the estimated fair value of the SOCAs. ACE employed a discount rate reflective of the estimated weighted average cost of capital for merchant generation companies since payments under the SOCAs are contingent on providing generation capacity.

The tables below summarize the primary unobservable inputs used to determine the fair value of PHI’s level 3 instruments and the range of values that could be used for those inputs as of March 31, 2013 and December 31, 2012:

Type of Instrument	Fair Value at March 31, 2013			Valuation Technique		Unobservable Input		Range
	(millions of dollars)
Capacity contracts, net	$	(3	)		Discounted cash flow		Discount rate	6% - 8%

Type of Instrument	Fair Value at December 31, 2012			Valuation Technique	Unobservable Input	Range
	(millions of dollars)
Natural gas options	$	(4	)	Option model	Volatility factor	1.57 - 2.00
Capacity contracts, net		(3	)	Discounted cash flow	Discount rate	5% - 9%

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PHI used values within these ranges as part of its fair value estimates. A significant change in any of the unobservable inputs within these ranges would have an insignificant impact on the reported fair value as of March 31, 2013 and December 31, 2012.

Executive deferred compensation plan assets and liabilities include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by PHI for reasonableness.

Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (Level 3) for the three months ended March 31, 2013 and 2012 are shown below:

	Three Months Ended March 31, 2013
	Natural Gas			Life Insurance Contracts		Capacity
	(millions of dollars)
Beginning balance as of January 1	$	(4	)	$	18	$	(3	)
Total gains (losses) (realized and unrealized):
Included in income		—			1		—
Included in accumulated other comprehensive loss		—			—		—
Included in regulatory liabilities		—			—		—
Purchases		—			—		—
Issuances		—			—		—
Settlements		4			—		—
Transfers in (out) of level 3		—			—		—
Ending balance as of March 31	$	—		$	19	$	(3	)

	Three Months Ended March 31, 2012
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(15	)	$	17
Total gains (losses) (realized and unrealized):
Included in income		—			1
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(3	)		—
Purchases		—			—
Issuances		—			—
Settlements		6			—
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	(12	)	$	18

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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:

	Three Months Ended March 31,
	2013		2012
	(millions of dollars)
Total net gains included in income for the period	$	1	$	1
Change in unrealized gains relating to assets still held at reporting date	$	1	$	1

Other Financial Instruments

The estimated fair values of PHI’s debt instruments that are measured at amortized cost in PHI’s consolidated financial statements and the associated level of the estimates within the fair value hierarchy as of March 31, 2013 and December 31, 2012 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy 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, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt categorized as level 1 is based on actual quoted trade prices for the debt in active markets on the measurement date.

The fair value of Long-term debt and Transition Bonds issued by ACE Funding categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt in active markets, but not on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and PHI reviews the methodologies and results.

The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient. The Long-Term project funding represents debt instruments issued by Pepco Energy Services related to its energy savings contracts. Long-Term project funding is categorized as level 3 because PHI concluded that the amortized cost carrying amounts for these instruments approximates fair value, which does not represent a quoted price in an active market.

	Fair Value Measurements at March 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	5,194	$	386	$	4,326	$	482
Transition Bonds issued by ACE Funding (b)		327		—		327		—
Long-term project funding		13		—		—		13
	$	5,534	$	386	$	4,653	$	495

(a) The carrying amount for Long-term debt is $4,426 million as of March 31, 2013.

(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $285 million as of March 31, 2013.

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	Fair Value Measurements at December 31, 2012
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	5,004	$	204	$	4,313	$	487
Transition Bonds issued by ACE Funding (b)		341		—		341		—
Long-term project funding		13		—		—		13
	$	5,358	$	204	$	4,654	$	500

(a) The carrying amount for Long-term debt is $4,177 million as of December 31, 2012.

(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $295 million as of December 31, 2012.

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

(15) COMMITMENTS AND CONTINGENCIES

General Litigation and Other Matters

In September 2011, an asbestos complaint was filed in the New Jersey Superior Court, Law Division, against ACE (among other defendants) asserting claims under New Jersey’s Wrongful Death and Survival statutes. The complaint, filed by the estate of a decedent who was the wife of a former employee of ACE, alleges that the decedent’s mesothelioma was caused by exposure to asbestos brought home by her husband on his work clothes. New Jersey courts have recognized a cause of action against a premise owner in a so-called “take home” case if it can be shown that the harm was foreseeable. In this case, the complaint seeks recovery of an unspecified amount of damages for, among other things, the decedent’s past medical expenses, loss of earnings, and pain and suffering between the time of injury and death, and asserts a punitive damage claim. At this time, ACE has concluded that a loss is reasonably possible with respect to this matter, but ACE was unable to estimate an amount or range of reasonably possible loss because (i) the damages sought are indeterminate, (ii) the proceedings are in the early stages, and (iii) the matter involves facts that ACE believes are distinguishable from the facts of the “take-home” cause of action recognized by the New Jersey courts. A trial date has been set for May 20, 2013.

During 2012, Pepco Energy Services received letters on behalf of two school districts in Maryland, which claim that invoices in connection with electricity supply contracts contained certain allegedly unauthorized charges, totaling approximately $7 million. The school districts also claim additional compounded interest totaling approximately $9 million. Pepco Energy Services disputes both the allegations regarding unauthorized charges and the claims of entitlement to compounded interest in their entirety, and has been in discussions with the school districts to attempt to resolve these claims. No litigation involving Pepco Energy Services related to these claims has commenced. As of March 31, 2013, the amount of loss that may be associated with these claims is not reasonably estimable, and Pepco Energy Services cannot estimate an amount or range of reasonably possible loss associated with the claims.

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Environmental Matters

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 PHI’s utility subsidiaries, environmental clean-up costs incurred by Pepco, DPL and ACE generally are included by each company in its respective cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies described below of PHI and its subsidiaries at March 31, 2013 are summarized as follows:

			Legacy Generation
	Transmission and  Distribution		Regulated		Non- Regulated		Other		Total
	(millions of dollars)
Beginning balance as of January 1	$	15	$	7	$	5	$	2	$	29
Accruals		—		—		—		—		—
Payments		—		1		—		—		1
Ending balance as of March 31		15		6		5		2		28
Less amounts in Other current liabilities		2		1		—		2		5
Amounts in Other deferred credits	$	13	$	5	$	5	$	—	$	23

Conectiv Energy Wholesale Power Generation Sites

In July 2010, PHI sold the Conectiv Energy wholesale power generation business to Calpine Corporation (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. The amount accrued by PHI for the ISRA-required remediation activities at the nine generating facility sites is included in the table above in the column entitled “Legacy Generation – Non-Regulated.”

In September 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 February 2004 and July 1, 2010, to demonstrate compliance with the Clean Air Act’s new source review permitting program. PHI responded to the data request. 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 adverse effect on its consolidated financial condition, results of operations or cash flows.

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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’s feasibility study for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million.

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. The National Priorities List, 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 September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with the RI/FS, any remediation activities to be performed at the site or any other 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 ACE, DPL and Pepco, based on their alleged sale of transformers to Ward Transformer, 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. The litigation is moving forward with certain “test case” defendants (not including ACE, DPL and Pepco) filing summary judgment motions regarding liability. The case has been stayed as to the

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remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The district court’s order addresses only the liability of the test case defendant. PHI has concluded that a loss is reasonably possible with respect to this matter, but PHI was unable to estimate an amount or range of reasonably possible losses to which it may be exposed. PHI does not believe that any of its three utility subsidiaries had extensive business transactions, if any, with the Ward Transformer site.

Benning Road Site

In September 2010, PHI received a letter from EPA identifying the Benning Road location, consisting of a generation facility operated by Pepco Energy Services until the facility was deactivated in June 2012, and a transmission and distribution facility operated by Pepco, 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. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the District of Columbia Department of the Environment (DDOE), which 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. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DDOE will look to the companies to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. The court order entering the consent decree requires the parties to submit a written status report to the court on May 24, 2013 regarding the implementation of the requirements of the consent decree and any related plans for remediation. In addition, if the RI/FS has not been completed by May 24, 2013, the status report must provide an explanation and a showing of good cause for why the work has not been completed.

Pepco and Pepco Energy Services submitted a proposed RI/FS work plan in July 2012, and filed a revised work plan in December 2012 based on comments from DDOE and the public. DDOE approved the revised work plan on December 28, 2012; RI/FS field work commenced in January 2013 and is still in progress.

The remediation costs accrued for this matter are included in the table above in the columns entitled “Transmission and Distribution,” “Legacy Generation – Regulated,” and “Legacy Generation – Non-Regulated.”

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. The amount of remediation costs accrued for this matter is included in the table above in the column entitled “Legacy Generation – Regulated.”

Potomac River Mineral Oil Release

In January 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.

Beginning in March 2011, DDOE issued a series of compliance directives requiring 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 completed field sampling during the fourth quarter of 2011 and submitted sampling results to DDOE during the second quarter of 2012. Pepco is continuing discussions with DDOE regarding the need for any further response actions but expects that additional monitoring of shoreline sediments may be required.

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In June 2012, Pepco commenced discussions with DDOE regarding a possible consent decree that would resolve DDOE’s threatened claims for civil penalties for alleged violation of the District’s Water Pollution Control Law, as well as for damages to natural resources. Pepco and DDOE have reached an agreement in principle that would consist of a combination of a civil penalty and Supplemental Environmental Projects (SEPs) with a total cost to Pepco of approximately $1 million. Discussions with DDOE continue regarding the specific nature and scope of the SEPs, as well as the amount of DDOE’s and the federal resource trustees’ natural resource damage claim. This matter is expected to be resolved through the entry of a consent decree sometime in 2013. Based on discussions to date, PHI and Pepco do not believe that the resolution of these claims will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

As a result of the oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility which involve pumping accumulated storm water to an aboveground holding tank for off-site disposal. In December 2011, Pepco completed the installation of a treatment system designed to allow automatic discharge of accumulated storm water from the secondary containment system. Pepco currently is seeking DDOE’s and EPA’s approval to commence operation of the new system. In the meantime, Pepco is continuing to use the aboveground holding tank to manage storm water from the secondary containment system.

The amounts accrued for these matters are included in the table above in the column entitled “Transmission and Distribution.”

Metal Bank Site

In January 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco (and contacted DPL in March 2013) on behalf of itself and other federal and state trustees to request that Pepco and DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Superfund Site located in Philadelphia, Pennsylvania. Pepco and DPL have executed the tolling agreement and will participate in settlement discussions with the NOAA, the trustees and other PRPs. While a loss associated with this matter is reasonably possible for Pepco and DPL, an estimate of the amount or range of reasonably possible loss cannot be made at this time because the matter is in its early stages and discussions with the NOAA and other parties have yet to commence; however, costs to resolve this matter are not expected to be material for Pepco and DPL in the aggregate.

PHI’s Cross-Border Energy Lease Investments

As discussed in Note (8), “Leasing Activities,” PHI has a portfolio of cross-border energy lease investments involving public utility assets located outside of the United States with a net investment value of approximately $869 million as of March 31, 2013. Each of these investments is comprised of multiple leases and each investment is structured as a sale and leaseback transaction commonly referred to by the IRS as a sale-in, lease-out, or SILO, transaction.

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 income tax returns, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI for six of the eight lease investments and, in connection with the audits of PHI’s 2003-2005 and 2006-2008 income tax returns, the IRS disallowed such deductions in excess of rental income for all eight of the lease investments. In addition, the IRS has sought to recharacterize each of the leases as a loan transaction in each of the years under audit as to which PHI would be subject to original issue discount income. PHI has disagreed with the IRS’ proposed adjustments to the 2001-2008 income tax returns and has filed protests of these findings for each year with the Office of Appeals of the IRS. In November 2010, PHI entered into a settlement agreement with the IRS for the 2001 and 2002 tax years solely for the purpose of commencing litigation associated with this matter and subsequently filed refund claims in July 2011 for the disallowed tax deductions relating to the

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leases for these years. In January 2011, 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. Since the July 2011 refund claims were not approved by the IRS within the statutory six-month period, in January 2012 PHI filed complaints in the U.S. Court of Federal Claims seeking recovery of the tax payment, interest and penalties. The 2003-2005 and 2006-2011 income tax return audits continue to be in process with the IRS Office of Appeals and the IRS Exam Division, respectively, and are not presently a part of the U.S. Court of Federal Claims litigation discussed above.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. While PHI believes that its tax position with regard to its cross-border energy lease investments is appropriate, after analyzing the recent U.S. Court of Appeals ruling, PHI has determined that its tax position with respect to the tax benefits associated with the cross-border energy leases no longer meets the more likely than not standard of recognition for accounting purposes. Accordingly, PHI recorded a non-cash charge of $377 million (after-tax) in the first quarter of 2013 (as discussed in Note (8), “Leasing Activities”), consisting of a charge to reduce the carrying value of the cross-border energy lease investments and a charge to reflect the anticipated additional interest expense related to changes in PHI’s estimated federal and state income tax obligations for the period over which the tax benefits ultimately may be disallowed. PHI had also previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. Management believes that it can no longer support its conclusions regarding these business assumptions, and the tax effects of this change in conclusion are included in the charge. While the IRS could require PHI to pay a penalty of up to 20% of the amount of additional taxes due, PHI believes that it is more likely than not that no such penalty will be incurred, and therefore no amount for any potential penalty was included in the charge recorded in the first quarter of 2013.

In the event that the IRS were to be successful in disallowing 100% of the tax benefits associated with these lease investments and recharacterizing these lease investments as loans, PHI estimated that, as of March 31, 2013, it would have been obligated to pay approximately $192 million in additional federal taxes (net of the $74 million tax payment described above) and approximately $50 million of interest on the additional federal taxes. These amounts, totaling $242 million, were estimated after consideration of certain tax benefits arising from matters unrelated to the leases that would offset the taxes and interest due, including PHI’s best estimate of the expected resolution of other uncertain and effectively settled tax positions, the carrying back and carrying forward of any existing net operating losses, and the application of certain amounts on deposit with the IRS. In order to mitigate PHI’s ongoing interest costs associated with the $242 million estimate of additional taxes and interest, PHI made a deposit with the IRS of $242 million in the first quarter of 2013. This deposit was funded from currently available sources of liquidity and short-term borrowings. PHI anticipates that any liquidation proceeds from lease terminations as described in Note (8), “Leasing Activities,” could be used to repay short-term borrowings utilized to fund the deposit.

PHI continues to weigh its options with respect to its litigation with the IRS. Pursuant to an agreement reached by the parties before the judge in January 2013, further discovery in the case is effectively stayed until July 1, 2013. The current schedule for the case requires that discovery be concluded by December 31, 2013, with a likely trial date in the second half of 2014.

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

PHI 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.

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As of March 31, 2013, PHI and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, energy procurement obligations, and other commitments and obligations. The commitments and obligations, in millions of dollars, were as follows:

	Guarantor
	PHI		Pepco		DPL		ACE		Total
Energy procurement obligations of Pepco Energy Services (a)	$	75	$	—	$	—	$	—	$	75
Guarantees associated with disposal of Conectiv Energy assets (b)		13		—		—		—		13
Guaranteed lease residual values (c)		2		5		7		4		18
Total	$	90	$	5	$	7	$	4	$	106

(a) PHI 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 of Conectiv Energy’s derivatives portfolio transferred in connection with the disposition of Conectiv Energy’s wholesale business. 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) Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $55 million, $8 million of which is a guaranty by PHI, $15 million by Pepco, $19 million by DPL and $13 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

PHI 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 Services Performance Contracts

Pepco Energy Services has a diverse portfolio of energy savings services performance contracts that are associated with the installation of energy savings equipment or combined heat and power facilities for federal, state and local government customers. As part of the energy savings contracts, Pepco Energy Services typically guarantees that the equipment or systems it installs will generate a specified amount of energy savings on an annual basis over a multi-year period. As of March 31, 2013, the remaining notional amount of Pepco Energy Services’ energy savings guarantees on both completed projects and projects under construction totaled $441 million over the life of the multi-year performance contracts with the longest guarantee having a remaining term of 13 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.

As of March 31, 2013, Pepco Energy Services had a performance guarantee contract associated with the production at a combined heat and power facility that is under construction totaling $15 million in notional value over the life of the multi-year contracts, with the longest guarantee having a remaining term of 20 years.

Pepco Energy Services recognizes a liability for the value of the estimated energy savings or production shortfalls when it is probable that the guaranteed amounts will not be achieved and the amount is reasonably estimable. As of March 31, 2013, Pepco Energy Services had an accrued liability of $1 million for its energy savings or combined heat and power performance contracts that it established during 2012. There was no significant change in the type of contracts issued during the three months ended March 31, 2013 as compared to the three months ended March 31, 2012.

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Dividends

On April 25, 2013, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable June 28, 2013, to stockholders of record on June 10, 2013.

(16) ACCUMULATED OTHER COMPREHENSIVE LOSS

The components of Pepco Holdings’ AOCL relating to continuing operations are as follows. For additional information, see the consolidated statements of comprehensive income.

	Three Months Ended March 31,
	2013			2012
Balance, beginning of period	$	(45	)	$	(50	)
Commodity Derivatives
Balance, beginning of period		(3	)		(16	)
Amount of net pre-tax loss reclassified into income:
Fuel and Purchased Energy expense		3			7
Revenue		—			—
Total net pre-tax loss reclassified into income		3			7
Income Tax expense		(1	)		(2	)
Net change during period		2			5
Balance, end of period		(1	)		(11	)
Treasury Lock
Balance, beginning of period		(10	)		(10	)
Amount of net pre-tax loss reclassified into income:
Interest expense		—			—
Total net pre-tax loss reclassified into income		—			—
Income Tax expense		—			—
Net change during period		—			—
Balance, end of period		(10	)		(10	)
Pension and Other Postretirement Benefit Plans
Balance, beginning of period		(32	)		(24	)
Amount of net pre-tax loss reclassified into income:
Other Operation and Maintenance expense		2			1
Total net pre-tax loss reclassified into income		2			1
Income Tax expense		(1	)		(1	)
Net change during period		1			—
Balance, end of period		(31	)		(24	)
Balance, end of period	$	(42	)	$	(45	)

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PEPCO HOLDINGS

(17) DISCONTINUED OPERATIONS

On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all of the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, gas inventory and derivative contracts. The transaction was completed on April 1, 2013. The agreement eliminated the retail natural gas supply business from the ongoing operations of Pepco Energy Services effective April 1, 2013 and Pepco Energy Services will not have significant continuing involvement in the retail natural gas supply business thereafter. As a result, PHI commenced reporting the results of operations of Pepco Energy Services’ retail natural gas supply business in discontinued operations in all periods presented in the accompanying consolidated statements of income. Further, certain assets and liabilities of Pepco Energy Services’ retail natural gas supply business are reported as held for sale as of each date presented in the accompanying consolidated balance sheets. Upon completion of the transaction, Pepco Energy Services received $8 million of collateral that it had pledged against its retail natural gas supply derivatives.

Operating Results

The operating results for the retail natural gas supply business of Pepco Energy Services are as follows:

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
Income from operations of discontinued operations, net of income taxes	$	2		$	5
Unrealized losses associated with retail natural gas supply contracts, net of income taxes		(2	)		—
Income From Discontinued Operations, Net of Income Taxes	$	—		$	5

Unrealized losses associated with retail natural gas supply contracts, net of income taxes includes unrealized derivative losses that were previously included in AOCL and were reclassified to income upon entering into the March 21, 2013 agreement, because PHI determined that the hedged forecasted purchases of supply for retail natural gas customers were probable not to occur. Accordingly, during the first quarter of 2013, PHI recognized $4 million of pre-tax unrealized derivative losses ($2 million after tax) that previously were included in AOCL as cash flow hedges. As a result of the completion of the transaction in the second quarter of 2013, PHI expects to record a pre-tax gain of approximately $8 million ($5 million after tax).

Balance Sheet Information

As March 31, 2013 and December 31, 2012, the retail natural gas supply business of Pepco Energy Services had inventory assets of less than $1 million and $1 million, respectively, and gross derivative liabilities of $8 million and $12 million, respectively, exclusive of the collateral pledged by Pepco Energy Services against the derivative liabilities. The fair value of the derivative liabilities were considered level 1 within the fair value hierarchy.

Derivative Instruments and Hedging Activities

Derivatives were used by the retail natural gas supply business of Pepco Energy Services to hedge commodity price risk.

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PEPCO HOLDINGS

The retail natural gas supply business of Pepco Energy Services entered into energy commodity contracts in the form of natural gas futures, swaps, options and forward contracts to hedge commodity price risk in connection with the purchase of physical natural gas for distribution to customers. The primary risk management objective was 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 became available.

Commodity contracts held by the retail natural gas supply business of Pepco Energy Services that were not designated for hedge accounting, did not qualify for hedge accounting, or did not meet the requirements for normal purchase and normal sale accounting, were marked to market through current earnings. Forward contracts that met the requirements for normal purchase and normal sale accounting were recorded on an accrual basis.

The tables below identify the balance sheet location and fair values of the retail natural gas supply business’ derivative instruments as of March 31, 2013 and December 31, 2012:

	As of March 31, 2013
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)	$	—		$	(7	)	$	(7	)	$	7	$	—
Derivative liabilities (non-current liabilities)		—			(1	)		(1	)		1		—
Net Derivative liability	$	—		$	(8	)	$	(8	)	$	8	$	—
	As of December 31, 2012
Balance Sheet Caption	Derivatives Designated as Hedging Instruments (a)			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative liabilities (current liabilities)	$	(5	)	$	(5	)	$	(10	)	$	10	$	—
Derivative liabilities (non-current liabilities)		(1	)		(1	)		(2	)		2		—
Net Derivative (liability) asset	$	(6	)	$	(6	)	$	(12	)	$	12	$	—

(a) Amounts included in Derivatives Designated as Hedging Instruments primarily consist of derivatives that were designated as cash flow hedges prior to Pepco Energy Services’ election to discontinue cash flow hedge accounting for these derivatives.

Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), the retail natural gas supply business of Pepco Energy Services 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. No derivative assets or liabilities were available to be offset under master netting arrangements as of March 31, 2013 and December 31, 2012. The amount of cash collateral that was offset against these derivative positions is as follows:

	March 31, 2013		December 31, 2012
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	8	$	12

(a) Includes cash deposits on commodity brokerage accounts.

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PEPCO HOLDINGS

As of March 31, 2013 and December 31, 2012, all cash collateral pledged by the retail gas business 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

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. The retail natural gas supply business of Pepco Energy Services had elected to no longer apply cash flow hedge accounting to its natural gas derivatives. Amounts included in AOCL for these cash flow hedges as of March 31, 2013 and 2012 represent net losses on derivatives prior to the election to discontinue cash flow hedge accounting less amounts reclassified into income as the hedged transactions occurred or because the hedged transactions were deemed probable not to occur. Gains or losses on these derivatives after the election to discontinue cash flow hedge accounting were recognized in income.

The cash flow hedge activity during the three months ended March 31, 2013 and 2012 is provided in the tables below:

	Three Months Ended March 31,
	2013		2012
	(millions of dollars)
Amount of net pre-tax loss arising during the period included in Accumulated Other Comprehensive Loss	$	—	$	—
Amount of net pre-tax loss reclassified into income:
Effective portion:
Income from Discontinued Operations, Net of Income Taxes		1		6
Ineffective portion: (a)
Income from Discontinued Operations, Net of Income Taxes		4		—
Total net pre-tax loss reclassified into Income from Discontinued Operations, Net of Income Taxes		5		6
Net pre-tax gain on commodity derivatives included in Accumulated Other Comprehensive Loss	$	5	$	6

(a) Included in the table above is a loss of $4 million for the three months ended March 31, 2013, which was reclassified from AOCL to Income from Discontinued Operations, Net of Income Taxes because the forecasted hedged transactions were deemed probable not to occur. For the three months ended March 31, 2012, no amounts were reclassified from AOCL to Income from Discontinued Operations, Net of Income Taxes because the forecasted hedged transactions were deemed probable not to occur.

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

Cash flow hedges are marked to market on the balance sheet with corresponding adjustments to AOCL for effective cash flow hedges. As of March 31, 2013, all of the losses in AOCL that were associated with derivatives that the retail natural gas supply business of Pepco Energy Services had previously designated as cash flow hedges have been reclassified to income. The table below provides details regarding effective cash flow hedges included in the retail natural gas supply business of Pepco Energy Services’ balance sheets as of March 31, 2012. Although the retail natural gas supply business of Pepco Energy Services elected to no longer apply cash flow hedge accounting to its derivatives prior to March 31, 2012, gains or losses previously deferred in AOCL prior to the decision to discontinue cash flow hedge accounting remained in AOCL until the hedged forecasted transaction occurred unless it was deemed probable that the hedged forecasted transaction would not occur. The data in the following 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:

Contracts	As of March 31, 2012				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Energy commodity (a)	$	10	$	7		26 months
Total	$	10	$	7

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(a) The unrealized derivative losses recorded in AOCL relate to forecasted physical natural gas purchases which are used to supply retail natural gas contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on the retail natural gas supply business of Pepco Energy Services’ balance sheet and the purchase cost is not recognized until the period of distribution.

Other Derivative Activity

The retail natural gas supply business of Pepco Energy Services held certain derivatives that were not in hedge accounting relationships and were not designated as normal purchases or normal sales. These derivatives were recorded at fair value on the balance sheet with the gain or loss for changes in fair value recorded through Income from Discontinued Operations, Net of Income Taxes.

For the three months ended March 31, 2013 and 2012, the amount of the derivative gain (loss) for the retail natural gas supply business of Pepco Energy Services recognized in Income from Discontinued Operations, Net of Income Taxes is provided in the table below:

	Three Months Ended March 31,
	2013			2012
	(millions of dollars)
Reclassification of mark-to-market to realized on settlement of contracts	$	2		$	8
Unrealized mark-to-market loss		(3	)		(6	)
Total net (loss) gain	$	(1	)	$	2

As of March 31, 2013 and December 31, 2012, the retail natural gas supply business of Pepco Energy Services had the following net outstanding commodity forward contract quantities and net position on derivatives that did not qualify for hedge accounting:

	March 31, 2013				December 31, 2012
Commodity	Quantity		Net Position		Quantity		Net Position
Natural gas (MMBtu)		2,047,500		Long		2,867,500		Long

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March 31,
	2013			2012
	(millions of dollars)
Operating Revenue	$	477		$	465
Operating Expenses
Purchased energy		192			185
Other operation and maintenance		102			103
Depreciation and amortization		47			47
Other taxes		89			90
Total Operating Expenses		430			425
Operating Income		47			40
Other Income (Expenses)
Interest expense		(26	)		(25	)
Other income		4			4
Total Other Expenses		(22	)		(21	)
Income Before Income Tax Expense (Benefit)		25			19
Income Tax Expense (Benefit)		2			(5	)
Net Income	$	23		$	24

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	March 31, 2013			December 31, 2012
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	97		$	9
Accounts receivable, less allowance for uncollectible accounts of $12 million and $13 million, respectively		321			318
Inventories		71			69
Prepayments of income taxes		9			9
Income taxes receivable		120			31
Prepaid expenses and other		23			25
Total Current Assets		641			461
INVESTMENTS AND OTHER ASSETS
Regulatory assets		493			487
Prepaid pension expense		349			353
Investment in trust		31			31
Income taxes receivable		18			102
Other		63			59
Total Investments and Other Assets		954			1,032
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		6,939			6,850
Accumulated depreciation		(2,704	)		(2,705	)
Net Property, Plant and Equipment		4,235			4,145
TOTAL ASSETS	$	5,830		$	5,638

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

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POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

	March 31, 2013		December 31, 2012
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	—	$	231
Current portion of long-term debt		200		200
Accounts payable and accrued liabilities		175		214
Accounts payable due to associated companies		49		41
Capital lease obligations due within one year		9		8
Taxes accrued		22		58
Interest accrued		39		17
Liabilities and accrued interest related to uncertain tax positions		24		—
Other		110		106
Total Current Liabilities		628		875
DEFERRED CREDITS
Regulatory liabilities		145		141
Deferred income taxes, net		1,249		1,219
Investment tax credits		3		4
Other postretirement benefit obligations		66		66
Liabilities and accrued interest related to uncertain tax positions		10		53
Other		68		66
Total Deferred Credits		1,541		1,549
LONG-TERM LIABILITIES
Long-term debt		1,751		1,501
Capital lease obligations		69		70
Total Long-Term Liabilities		1,820		1,571
COMMITMENTS AND CONTINGENCIES (NOTE 11)
EQUITY
Common stock, $.01 par value, 200,000,000 shares authorized, 100 shares outstanding		—		—
Premium on stock and other capital contributions		930		755
Retained earnings		911		888
Total Equity		1,841		1,643
TOTAL LIABILITIES AND EQUITY	$	5,830	$	5,638

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

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POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	23		$	24
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		47			47
Deferred income taxes		26			127
Changes in:
Accounts receivable		(2	)		35
Inventories		(2	)		(4	)
Prepaid expenses		3			4
Regulatory assets and liabilities, net		(9	)		(14	)
Accounts payable and accrued liabilities		(14	)		(7	)
Prepaid pension expense, excluding contributions		4			6
Pension contributions		—			(85	)
Income tax-related prepayments, receivables and payables		(60	)		(139	)
Interest accrued		21			19
Other assets and liabilities		—			(3	)
Net Cash From Operating Activities		37			10
INVESTING ACTIVITIES
Investment in property, plant and equipment		(125	)		(158	)
Department of Energy capital reimbursement awards received		1			6
Net other investing activities		(3	)		2
Net Cash Used By Investing Activities		(127	)		(150	)
FINANCING ACTIVITIES
Capital contribution from Parent		175			—
Issuance of long-term debt		250			—
(Reacquisitions) Issuances of short-term debt, net		(231	)		130
Cost of issuances		(4	)		(3	)
Net other financing activities		(12	)		8
Net Cash From Financing Activities		178			135
Net Increase (Decrease) in Cash and Cash Equivalents		88			(5	)
Cash and Cash Equivalents at Beginning of Period		9			12
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	97		$	7
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for income taxes (includes payments to (from) PHI for federal income taxes)	$	—		$	1

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

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POTOMAC ELECTRIC POWER COMPANY

STATEMENT OF EQUITY

(Unaudited)

	Common Stock				Premium on Stock		Retained Earnings		Total
(millions of dollars, except shares)	Shares		Par Value
BALANCE, DECEMBER 31, 2012		100	$	—	$	755	$	888	$	1,643
Net Income		—		—		—		23		23
Capital contribution from Parent		—		—		175		—		175
BALANCE, MARCH 31, 2013		100	$	—	$	930	$	911	$	1,841

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 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, 2012. 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 March 31, 2013, in accordance with GAAP. The year-end December 31, 2012 balance sheet included herein was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2013 may not be indicative of results that will be realized for the full year ending December 31, 2013.

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, future cash flows and fair value amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, 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.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $77 million and $78 million for the three months ended March 31, 2013 and 2012, respectively.

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Reclassifications

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

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

None.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Joint and Several Liability Arrangements (Accounting Standards Codification (ASC) 405)

In February 2013, the Financial Accounting Standards Board (FASB) issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, Pepco will be required to include in its liabilities the additional amounts it expects to pay on behalf of its co-obligors, if any. Pepco will also be required to provide additional disclosures including the nature of the arrangements with its co-obligors, the total amounts outstanding under the arrangements between Pepco and its co-obligors, the carrying value of the liability, and the nature and limitations of any recourse provisions that would enable recovery from other entities.

The new requirements would be effective retroactively beginning on January 1, 2014, with implementation required for prior periods if joint and several liability arrangement obligations exist as of January 1, 2014. Pepco is evaluating the impact of this new guidance on its financial statements.

(5) SEGMENT INFORMATION

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

(6) REGULATORY MATTERS

Rate Proceedings

Over the last several years, Pepco has proposed in each of its jurisdictions 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) was approved and implemented for electric service in Maryland and the District of Columbia. 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.

District of Columbia

On March 8, 2013, Pepco filed an application with the District of Columbia Public Service Commission (DCPSC) to increase its electric distribution base rates by approximately $52.1 million annually, based on a requested return on equity (ROE) of 10.25%. The requested rate increase is for the purpose of recovering (i) Pepco’s expenses associated with ongoing efforts to maintain safe and reliable service for its customers, (ii) Pepco’s investment in infrastructure to maintain and harden the electric distribution system, and (iii) Pepco’s major reliability enhancement improvements. A final DCPSC decision is expected by the fourth quarter of 2013.

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Maryland

In December 2011, Pepco submitted an application with the Maryland Public Service Commission (MPSC) to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently reduced by Pepco to $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving, an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorizes Pepco to recover the actual cost of advanced metering infrastructure (AMI) meters installed during the test year and states that cost recovery for AMI deployment will only be allowed in future rate cases in which Pepco demonstrates that the system is proven to be cost effective. The new revenue rates and lower depreciation rates were effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of installed AMI meters; that motion remains pending.

On November 30, 2012, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $60.8 million, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering reliability enhancements to serve Maryland customers. Pepco also proposes a three-year Grid Resiliency Charge rider for recovery of costs totaling approximately $192 million associated with its plan to accelerate investments in infrastructure in a condensed timeframe. Acceleration of resiliency improvements is one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below). The Grid Resiliency Charge, if approved, would become effective January 1, 2014 and be implemented as a rider that is separate from base rates and would include a return on investment. Specific projects under Pepco’s plan include acceleration of its tree-trimming cycle, upgrade of 12 additional feeders per year for two years and undergrounding of six distribution feeders. In addition, Pepco proposes a reliability performance-based mechanism that would allow Pepco to earn up to $1 million as an incentive for meeting enhanced reliability goals in 2015, but provides a credit to customers of up to $1 million in total if Pepco does not meet at least the minimum reliability performance targets. Pepco requests that any credits/charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the third quarter of 2013.

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland 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.

In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 megawatts (MW) beginning in 2015. The order requires Pepco, Delmarva Power & Light Company (DPL) and Baltimore Gas and Electric Company (BGE) (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process in amounts proportional to their relative Standard Offer Service (SOS) loads. Under the contract, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015. The order acknowledged the Contract EDCs’ concerns about the requirements of the contract and directed them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specified that the Contract EDCs will recover the associated costs through surcharges on their respective SOS customers.

In April 2012, a group of generating companies operating in the PJM Interconnection, LLC (PJM) region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, the Contract EDCs and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These circuit court appeals were consolidated in the Circuit Court for Baltimore City and stayed pending the issuance of a final order from the MPSC approving the form of contract.

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On April 16, 2013, the MPSC issued an order approving a final form of the contract and directing the Contract EDCs to enter into the contract, in amounts proportional to their relative SOS loads, with the winning bidder within 20 days of the order (i.e., by May 6, 2013). The MPSC stated that the order, which approves timely and complete recovery by the Contract EDCs of the costs associated with the contract, constitutes a binding commitment that shall not be subject to future modification or rescission by the MPSC. Despite this commitment from the MPSC, Pepco believes that the attempt by the MPSC to bind a future commission in this manner may be subject to legal challenge, which challenge, if successful, could impair its right to recover its costs in the future. In addition, the MPSC excluded from the contract a provision that Pepco believes is important to mitigate its financial risk because the provision, had it been included, would have required Pepco to make payments to the winning bidder under the contract only to the extent it was able to recover those costs (for example, Pepco believes the excluded provision would have protected it in the event a significant number of SOS customers elect to buy their energy from alternative energy suppliers). In light of the issuance of the MPSC’s final order, the previously filed appeals of the MPSC’s actions in this case before the circuit court will now proceed. Pepco anticipates that, in accordance with the terms of the MPSC’s order, it will enter into the contract within the 20-day period; however, under its own terms, the contract will not become effective, if at all, until all legal proceedings related to this contract or the actions of the MPSC in the related proceeding have been resolved.

Until a final non-appealable court decision is rendered in connection with all such legal proceedings, Pepco cannot predict (i) the extent of the negative effect that the contract for new generation may have on Pepco’s balance sheets, as well as its credit metrics, as calculated by independent rating agencies that evaluate and rate Pepco and each of its debt issuances, (ii) the effect on Pepco’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contract on the financial condition, results of operations and cash flows of Pepco.

Reliability Task Forces

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. Pepco’s electric distribution base rate case filed with the MPSC on November 30, 2012 addresses the Grid Resiliency Task Force recommendations.

In August 2012, the District of Columbia mayor issued an Executive Order establishing the Mayor’s Power Line Undergrounding Task Force. The stated purpose of the Power Line Undergrounding Task Force is to pool the collective resources available in the District of Columbia to produce an analysis of the technical feasibility, infrastructure options and reliability implications of undergrounding new or existing overhead distribution facilities in the District of Columbia. These resources include legislative bodies, regulators, utility personnel, experts and other parties who could contribute in a meaningful way to the Power Line Undergrounding Task Force. The options that are available for financing these efforts are also to be evaluated to identify required legislative or regulatory actions to implement these recommendations. The results of this analysis are intended to help determine the path forward for these types of infrastructure improvements and additions. A written report from the Power Line Undergrounding Task Force setting forth the findings and recommendations was originally due on January 31, 2013 but the due date was extended to the second quarter of 2013.

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MAPP Project

On August 24, 2012, the board of PJM terminated the Mid-Atlantic Power Pathway (MAPP) project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. As of December 31, 2012, Pepco’s total costs related to the MAPP project were $64 million. In a 2008 Federal Energy Regulatory Commission (FERC) order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, Pepco submitted a filing to FERC seeking recovery of $50 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

Various protests were submitted in response to Pepco’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of Pepco, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by Pepco to be $1 million) of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. Pepco believes that the FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request on behalf of Pepco of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that Pepco is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. Pepco cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, Pepco had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories, for use on other projects, and reclassified the remaining $50 million of capital expenditures to a regulatory asset. During the first quarter of 2013, Pepco further transferred an additional $2 million of materials to inventories, for use on other projects, and expensed $1 million of abandoned costs as a result of FERC’s disallowance noted above, resulting in a regulatory asset of $47 million as of March 31, 2013. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. Pepco intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey filed a joint complaint with FERC against Pepco, DPL and Atlantic City Electric Company (ACE), as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that Pepco provides. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for Pepco is (i) 11.3% for facilities placed into

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service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. Pepco believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, Pepco filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

(7) PENSION AND OTHER POSTRETIREMENT BENEFITS

Pepco accounts for its participation in its parent’s single-employer plans, Pepco Holding’s non-contributory 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 March 31, 2013 and 2012, before intercompany allocations from the PHI Service Company, were $25 million and $26 million, respectively. Pepco’s allocated share was $8 million and $11 million, respectively, for the three months ended March 31, 2013 and 2012.

In the first quarter of 2012, Pepco made a discretionary tax-deductible contribution to the PHI Retirement Plan of $85 million.

(8) DEBT

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement, which among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility.

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 is $750 million for PHI 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 the one month London Interbank Offered Rate 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 and other 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

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to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, 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 credit agreement contains certain covenants and other customary agreements and requirements that, if not 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 covenants under this facility as of March 31, 2013.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

At March 31, 2013 and December 31, 2012, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $635 million and $477 million, respectively. Pepco’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by DPL and ACE and the portion of the total capacity being used by PHI.

Commercial Paper

Pepco maintains an on-going commercial paper program to address its short-term liquidity needs. As of March 31, 2013, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

Pepco had no commercial paper outstanding at March 31, 2013. The weighted average interest rate for commercial paper issued by Pepco during the three months ended March 31, 2013 was 0.38% and the weighted average maturity of all commercial paper issued by Pepco during the three months ended March 31, 2013 was seven days.

Other Financing Activities

In March 2013, Pepco issued $250 million of 4.15% first mortgage bonds due March 15, 2043. These bonds were issued under a Mortgage and Deed of Trust and are secured thereunder by a first lien, subject to certain leases, permitted liens and other exceptions, on substantially all of Pepco’s properties. Net proceeds from the issuance of the long-term debt were used to repay Pepco’s outstanding commercial paper that was issued to temporarily fund capital expenditures, provide working capital and for general corporate purposes.

(9) INCOME TAXES

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

	Three Months Ended March 31,
	2013					2012
	(millions of dollars)
Income tax at Federal statutory rate	$	9		35.0	%	$	7		35.0	%
Increases (decreases) resulting from:
State income taxes, net of Federal effect		2		8.0	%		1		6.3	%
Asset removal costs		(3	)	(12.0	)%		(3	)	(15.8	)%
Changes in estimates and interest related to uncertain and effectively settled tax positions		(5	)	(20.0	)%		(10	)	(50.5	)%
Other, net		(1	)	(3.0	)%		—		(1.3	)%
Income tax expense (benefit)	$	2		8.0	%	$	(5	)	(26.3	)%

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Pepco’s effective tax rates for the three months ended March 31, 2013 and 2012 and were 8.0% and (26.3)%, respectively. The increase in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which Pepco is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that it can no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded a charge of $377 million (after-tax) in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in Pepco recording a $5 million interest benefit in the first quarter of 2013.

In the first quarter of 2012, Pepco recorded benefits for changes in estimates and interest related to uncertain and effectively settled tax positions primarily due to the effective settlement with the Internal Revenue Service with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position.

(10) 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).

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 March 31, 2013 and December 31, 2012. 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.

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	Fair Value Measurements at March 31, 2013
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	$	85	$	85	$	—	$	—
Executive deferred compensation plan assets
Money market funds		14		14		—		—
Life insurance contracts		57		—		39		18
	$	156	$	99	$	39	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	8	$	—	$	8	$	—
	$	8	$	—	$	8	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.

	Fair Value Measurements at December 31, 2012
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		56		—		38		18
	$	71	$	15	$	38	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	9	$	—	$	9	$	—
	$	9	$	—	$	9	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.

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.

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 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.

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Executive deferred compensation plan assets consist of life insurance policies and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued 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 and can be liquidated for the value of the underlying assets as of March 31, 2013. 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.

The value of certain employment agreement obligations is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data.

Level 3 – Pricing inputs that are significant and 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 include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by Pepco for reasonableness.

Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (level 3) for the three months ended March 31, 2013 and 2012, are shown below:

	Life Insurance Contracts
	Three Months Ended March 31,
	2013			2012
	(millions of dollars)
Beginning balance as of January 1	$	18		$	17
Total gains (losses) (realized and unrealized):
Included in income		1			1
Included in accumulated other comprehensive loss		—			—
Purchases		—			—
Issuances		(1	)		—
Settlements		—			—
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	18		$	18

The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other Operation and Maintenance expense for the periods below were as follows:

	Three Months Ended March  31,
	2013		2012
	(millions of dollars)
Total gains included in income for the period	$	1	$	1
Change in unrealized gains relating to assets still held at reporting date	$	1	$	1

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Other Financial Instruments

The estimated fair values of Pepco’s debt instruments that are measured at amortized cost in Pepco’s financial statements and the associated level of the estimates within the fair value hierarchy as of March 31, 2013 and December 31, 2012 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy 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, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt categorized as level 1 is based on actual quoted trade prices for the debt in active markets on the measurement date.

The fair value of Long-term debt categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt in active markets, but not on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and Pepco reviews the methodologies and results.

	Fair Value Measurements at March 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	2,387	$	371	$	2,016	$	—
	$	2,387	$	371	$	2,016	$	—

(a) The carrying amount for Long-term debt is $1,951 million as of March 31, 2013.

	Fair Value Measurements at December 31, 2012
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	2,160	$	204	$	1,956	$	—
	$	2,160	$	204	$	1,956	$	—

(a) The carrying amount for Long-term debt is $1,701 million as of December 31, 2012.

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

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(11) COMMITMENTS AND CONTINGENCIES

Environmental Matters

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 customers of Pepco, environmental clean-up costs incurred by Pepco generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of Pepco described below at March 31, 2013 are summarized as follows:

	Transmission and Distribution		Legacy Generation - Regulated		Total
	(millions of dollars)
Beginning balance as of January 1	$	14	$	3	$	17
Accruals		—		—		—
Payments		—		—		—
Ending balance as of March 31		14		3		17
Less amounts in Other current liabilities		1		—		1
Amounts in Other deferred credits	$	13	$	3	$	16

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 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. The National Priorities List, 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 September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with the RI/FS, any remediation activities to be performed at the site or any other 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, based on its alleged sale of transformers to Ward Transformer, 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. The litigation is moving forward with certain “test case” defendants (not including Pepco) filing summary

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judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The district court’s order addresses only the liability of the test case defendant. Pepco has concluded that a loss is reasonably possible with respect to this matter, but was unable to estimate an amount or range of reasonably possible losses to which it may be exposed. Pepco does not believe that it had extensive business transactions, if any, with the Ward Transformer site.

Benning Road Site

In September 2010, PHI received a letter from EPA identifying the Benning Road location, consisting of a generation facility operated by Pepco Energy Services and its subsidiaries (Pepco Energy Services) until the facility was deactivated in June 2012, and a transmission and distribution facility operated by Pepco, 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. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with District of Columbia Department of the Environment (DDOE), which 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. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DDOE will look to the companies to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. The court order entering the consent decree requires the parties to submit a written status report to the court on May 24, 2013 regarding the implementation of the requirements of the consent decree and any related plans for remediation. In addition, if the RI/FS has not been completed by May 24, 2013, the status report must provide an explanation and a showing of good cause for why the work has not been completed.

Pepco and Pepco Energy Services submitted a proposed RI/FS work plan in July 2012, and filed a revised work plan in December 2012 based on comments from DDOE and the public. DDOE approved the revised work plan on December 28, 2012; RI/FS field work commenced in January 2013 and is still in progress.

The remediation costs accrued for this matter are included in the table above in the columns entitled “Transmission and Distribution,” “Legacy Generation – Regulated,” and “Legacy Generation – Non-Regulated.”

Potomac River Mineral Oil Release

In January 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.

Beginning in March 2011, DDOE issued a series of compliance directives requiring 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 completed field sampling during the fourth quarter of 2011 and submitted sampling results to DDOE during the second quarter of 2012. Pepco is continuing discussions with DDOE regarding the need for any further response actions but expects that additional monitoring of shoreline sediments may be required.

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In June 2012, Pepco commenced discussions with DDOE regarding a possible consent decree that would resolve DDOE’s threatened claims for civil penalties for alleged violation of the District’s Water Pollution Control Law, as well as for damages to natural resources. Pepco and DDOE have reached an agreement in principle that would consist of a combination of a civil penalty and Supplemental Environmental Projects (SEPs) with a total cost to Pepco of approximately $1 million. Discussions with DDOE continue regarding the specific nature and scope of the SEPs, as well as the amount of DDOE’s and the federal resource trustees’ natural resource damage claim. This matter is expected to be resolved through the entry of a consent decree sometime in 2013. Based on discussions to date, PHI and Pepco do not believe that the resolution of these claims will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

As a result of the oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility which involve pumping accumulated storm water to an aboveground holding tank for off-site disposal. In December 2011, Pepco completed the installation of a treatment system designed to allow automatic discharge of accumulated storm water from the secondary containment system. Pepco currently is seeking DDOE’s and EPA’s approval to commence operation of the new system. In the meantime, Pepco is continuing to use the aboveground holding tank to manage storm water from the secondary containment system.

The amounts accrued for these matters are included in the table above in the column entitled “Transmission and Distribution.”

Metal Bank Site

In January 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco on behalf of itself and other federal and state trustees to request that Pepco execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Superfund Site located in Philadelphia, Pennsylvania. Pepco has executed the tolling agreement and will participate in settlement discussions with the NOAA, the trustees and other PRPs. While a loss associated with this matter is reasonably possible for Pepco, an estimate of the amount or range of reasonably possible loss cannot be made at this time because the matter is in its early stages and discussions with the NOAA and other parties have yet to commence; however, costs to resolve this matter are not expected to be material for Pepco.

(12) 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 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 March 31, 2013 and 2012 were approximately $55 million and $51 million, respectively.

Pepco Energy Services performs utility maintenance services and high voltage underground transmission cabling, including services that are treated as capital costs, for Pepco. Amounts charged to Pepco by Pepco Energy Services for the three months ended March 31, 2013 and 2012 were approximately $8 million and $5 million, respectively.

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PEPCO

As of March 31, 2013 and December 31, 2012, Pepco had the following balances on its balance sheets due to related parties:

	March 31, 2013			December 31, 2012
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(31	)	$	(22	)
Pepco Energy Services (b)		(17	)		(18	)
Other		(1	)		(1	)
Total	$	(49	)	$	(41	)

(a) Included in Accounts Payable Due to Associated Companies.

(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. Amount also includes charges for utility work performed by Pepco Energy Services on behalf of Pepco.

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DPL

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March 31,
	2013			2012
	(millions of dollars)
Operating Revenue
Electric	$	285		$	259
Natural gas		85			74
Total Operating Revenue		370			333
Operating Expenses
Purchased energy		159			143
Gas purchased		54			49
Other operation and maintenance		69			65
Depreciation and amortization		25			24
Other taxes		10			9
Total Operating Expenses		317			290
Operating Income		53			43
Other Income (Expenses)
Interest expense		(13	)		(11	)
Other income		2			3
Total Other Expenses		(11	)		(8	)
Income Before Income Tax Expense		42			35
Income Tax Expense		16			14
Net Income	$	26		$	21

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

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DPL

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	March 31, 2013			December 31, 2012
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	10		$	6
Accounts receivable, less allowance for uncollectible accounts of $14 million and $9 million, respectively		216			201
Inventories		48			53
Prepayments of income taxes		10			10
Income taxes receivable		6			10
Assets and accrued interest related to uncertain tax positions		17			—
Prepaid expenses and other		19			20
Total Current Assets		326			300
INVESTMENTS AND OTHER ASSETS
Goodwill		8			8
Regulatory assets		276			288
Prepaid pension expense		239			232
Assets and accrued interest related to uncertain tax positions		3			20
Other		12			12
Total Investments and Other Assets		538			560
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		3,479			3,422
Accumulated depreciation		(1,002	)		(1,000	)
Net Property, Plant and Equipment		2,477			2,422
TOTAL ASSETS	$	3,341		$	3,282

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

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DPL

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

	March 31, 2013		December 31, 2012
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	175	$	137
Current portion of long-term debt		250		250
Accounts payable and accrued liabilities		100		125
Accounts payable due to associated companies		22		20
Taxes accrued		5		4
Interest accrued		15		6
Derivative liabilities		—		4
Other		61		61
Total Current Liabilities		628		607
DEFERRED CREDITS
Regulatory liabilities		258		258
Deferred income taxes, net		716		697
Investment tax credits		5		5
Other postretirement benefit obligations		22		22
Other		34		41
Total Deferred Credits		1,035		1,023
LONG-TERM LIABILITIES
Long-term debt		667		667
COMMITMENTS AND CONTINGENCIES (NOTE 13)
EQUITY
Common stock, $2.25 par value, 1,000 shares authorized, 1,000 shares outstanding		—		—
Premium on stock and other capital contributions		407		407
Retained earnings		604		578
Total Equity		1,011		985
TOTAL LIABILITIES AND EQUITY	$	3,341	$	3,282

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

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DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	26		$	21
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		25			24
Deferred income taxes		17			41
Changes in:
Accounts receivable		(16	)		16
Inventories		5			4
Regulatory assets and liabilities, net		5			(7	)
Accounts payable and accrued liabilities		(9	)		(8	)
Pension contributions		(10	)		(85	)
Income tax-related prepayments, receivables and payables		1			(31	)
Interest accrued		9			6
Other assets and liabilities		1			4
Net Cash From (Used By) Operating Activities		54			(15	)
INVESTING ACTIVITIES
Investment in property, plant and equipment		(83	)		(69	)
Net other investing activities		1			(1	)
Net Cash Used By Investing Activities		(82	)		(70	)
FINANCING ACTIVITIES
Issuances of short-term debt, net		38			87
Net other financing activities		(6	)		(3	)
Net Cash From Financing Activities		32			84
Net Increase (Decrease) in Cash and Cash Equivalents		4			(1	)
Cash and Cash Equivalents at Beginning of Period		6			5
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	10		$	4
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for income taxes (includes payments to PHI for federal income taxes)	$	—		$	—

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

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DPL

DELMARVA POWER & LIGHT COMPANY

STATEMENT OF EQUITY

(Unaudited)

	Common Stock
(millions of dollars, except shares)	Shares		Par Value		Premium on Stock		Retained Earnings		Total
BALANCE, DECEMBER 31, 2012		1,000	$	—	$	407	$	578	$	985
Net Income		—		—		—		26		26
BALANCE, MARCH 31, 2013		1,000	$	—	$	407	$	604	$	1,011

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 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, 2012. 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 March 31, 2013, in accordance with GAAP. The year-end December 31, 2012 balance sheet included herein was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2013 may not be indicative of DPL’s results that will be realized for the full year ending December 31, 2013.

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, 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, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, 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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Consolidation of Variable Interest Entities—DPL Renewable Energy Transactions

DPL assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with ASC 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests.

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. As of March 31, 2013, PHI, through its DPL subsidiary, is a party to three land-based wind PPAs in the aggregate amount of 128 megawatts (MWs) and one solar PPA with a 10 MW facility. Each of the facilities associated with these PPAs is operational, and DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and solar renewable energy credits (SRECs) from the solar facility up to certain amounts (as set forth below) at rates that are primarily fixed under the PPAs. PHI has concluded that consolidation is not required for any of these PPAs under the Financial Accounting Standards Board (FASB) guidance on the consolidation of variable interest entities.

DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs, in each case at the rates primarily fixed by the PPA. DPL’s purchases under the three wind PPAs totaled $10 million and $9 million for the three months ended March 31, 2013 and 2012, respectively.

The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. DPL’s purchases under the solar agreement were less than one million and zero for the three months ended March 31, 2013 and 2012, respectively.

On October 18, 2011, the Delaware Public Service Commission (DPSC) approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. 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 MW hour (MWh) of energy produced by the fuel cell facilities over 21 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 provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. In June 2012, a 3 MW fuel cell generation facility was placed into service under the tariff. DPL billed $3 million and zero to distribution customers for the three months ended March 31, 2013 and 2012, respectively. A 27 MW fuel cell generation facility is expected to be placed into service over time, with the first 5 MW increment having been placed into service at the end of 2012. DPL has concluded that consolidation under the variable interest entity consolidation guidance is not required for this arrangement.

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 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 DPL below the carrying amount of its net assets. 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 March 31, 2013.

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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 March 31, 2013 and 2012.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Balance Sheet (Accounting Standards Codification (ASC) 210)

In December 2011, the FASB issued new disclosure requirements for financial assets and financial liabilities, such as derivatives, that are subject to contractual netting arrangements. The new disclosure requirements include information about the gross exposure of the instruments and the net exposure of the instruments under contractual netting arrangements, how the exposures are presented in the financial statements, and the terms and conditions of the contractual netting arrangements. As of March 31, 2013, DPL adopted the new guidance and concluded it did not have a material impact on its financial statements.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Joint and Several Liability Arrangements (ASC 405)

In February 2013, the FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, DPL will be required to include in its liabilities the additional amounts it expects to pay on behalf of its co-obligors, if any. DPL will also be required to provide additional disclosures including the nature of the arrangements with its co-obligors, the total amounts outstanding under the arrangements between DPL and its co-obligors, the carrying value of the liability, and the nature and limitations of any recourse provisions that would enable recovery from other entities.

The new requirements would be effective retroactively beginning on January 1, 2014, with implementation required for prior periods if joint and several liability arrangement obligations exist as of January 1, 2014. DPL is evaluating the impact of this new guidance on its financial statements.

(5) SEGMENT INFORMATION

DPL 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 months ended March 31, 2013. 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, 2012 indicated that goodwill was not impaired. For the three months ended March 31, 2013, 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, 2013.

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(7) REGULATORY MATTERS

Rate Proceedings

Over the last several years, DPL has proposed in each its jurisdictions 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) was approved and implemented for electric service in Maryland.

• A modified fixed variable rate design (MFVRD) is under consideration by the DPSC.

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

Delaware

Gas Cost Rates

DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2012, DPL made its 2012 GCR filing. The rates proposed in the 2012 GCR would result in a GCR decrease of approximately 22.3%. On September 18, 2012, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2012, subject to refund and pending final DPSC approval. On April 24, 2013, DPL and the DPSC staff entered into a settlement agreement providing that the proposed GCR rates as filed by DPL should be approved. The settlement agreement is subject to DPSC approval. A DPSC decision on the settlement agreement is expected by the end of the third quarter of 2013.

Electric Distribution Base Rates

In December 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $31.8 million, based on a requested return on equity (ROE) of 10.75%, and requested approval of implementation of the MFVRD. In accordance with Delaware law and agreement with DPSC staff, DPL placed a total of $24.8 million of the requested rate increase into effect, subject to refund and pending final DPSC order. In November 2012, the DPSC approved a proposed settlement agreement entered into by DPL and the other parties to the proceeding that provided, among other things, for an annual rate increase of $22 million, based on an ROE of 9.75%. In February 2013, DPL refunded the billed amounts that exceeded the increase approved by the DPSC.

On March 22, 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $42 million, based on a requested ROE of 10.25%. The requested rate increase seeks to recover expenses associated with DPL’s ongoing efforts to maintain safe and reliable service. In accordance with Delaware law and because the DPSC suspended, DPL’s full proposed increase, DPL plans to implement an interim increase of $2.5 million on June 1, 2013, subject to refund and pending final DPSC approval. A final DPSC decision is expected by the fourth quarter of 2013.

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Gas Distribution Base Rates

On December 7, 2012, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. The filing seeks approval of an annual rate increase of approximately $12.2 million, based on a requested ROE of 10.25%. The requested rate increase is for the purposes of recovering expenses associated with DPL’s ongoing efforts to maintain safe and reliable service and to provide enhanced customer service technology. In January 2013, the DPSC suspended the full proposed increase and, as permitted by state law, DPL implemented an interim increase of $2.5 million on February 5, 2013, subject to refund and pending final DPSC approval. A final DPSC decision is expected by the third quarter of 2013.

Maryland

Electric Distribution Base Rates

On March 29, 2013, DPL submitted an application with the Maryland Public Service Commission (MPSC) to increase its electric distribution base rates by approximately $22.8 million, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering reliability enhancements to serve Maryland customers. DPL also proposes a three-year Grid Resiliency Charge rider for recovery of costs totaling approximately $10.2 million associated with its plan to accelerate investments in electric distribution infrastructure in a condensed timeframe. Acceleration of resiliency improvements is one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below). The Grid Resiliency Charge, if approved, would become effective January 1, 2014 and be implemented as a rider that is separate from base rates and would include a reasonable return on investment. Specific projects under DPL’s plan include accelerating its tree-trimming cycle and upgrading five additional feeders per year for two years. In addition, DPL proposes a reliability performance-based mechanism that would allow DPL to earn up to $500,000 as an incentive for meeting enhanced reliability goals in 2015, but provides a credit to customers of up to $500,000 in total if DPL does not meet at least the minimum reliability performance targets. DPL requests that any credits or charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the fourth quarter of 2013.

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland 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.

In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 MW beginning in 2015. The order requires DPL, Potomac Electric Power Company (Pepco) and Baltimore Gas and Electric Company (BGE) (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process in amounts proportional to their relative Standard Offer Service (SOS) loads. Under the contract, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015. The order acknowledged the Contract EDCs’ concerns about the requirements of the contract and directed them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specified that the Contract EDCs will recover the associated costs through surcharges on their respective SOS customers.

In April 2012, a group of generating companies operating in the PJM Interconnection, LLC (PJM) region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, the Contract EDCs and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These appeals were consolidated in the Circuit Court for Baltimore City and stayed pending the issuance of a final order from the MPSC approving the form of contract.

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On April 16, 2013, the MPSC issued an order approving a final form of the contract and directing the Contract EDCs to enter into the contract, in amounts proportional to their relative SOS loads, with the winning bidder within 20 days of the order (i.e., by May 6, 2013). The MPSC stated that the order, which approves timely and complete recovery by the Contract EDCs of the costs associated with the contract, constitutes a binding commitment that shall not be subject to future modification or rescission by the MPSC. Despite this commitment from the MPSC, DPL believes that the attempt by the MPSC to bind a future commission in this manner may be subject to legal challenge, which challenge, if successful, could impair its right to recover its costs in the future. In addition, the MPSC excluded from the contract a provision that DPL believes is important to mitigate its financial risk because the provision, had it been included, would have required DPL to make payments to the winning bidder under the contract only to the extent it was able to recover those costs (for example, DPL believes the excluded provision would have protected it in the event a significant number of its SOS customers elect to buy their energy from alternative energy suppliers). In light of the issuance of the MPSC’s final order, the previously filed appeals of the MPSC’s actions in this case before the circuit court will now proceed. DPL anticipates that, in accordance with the terms of the MPSC’s order, it will enter into the contract within the 20-day period; however, under its own terms, the contract will not become effective, if at all, until all legal proceedings related to this contract or the actions of the MPSC in the related proceeding have been resolved.

Until a final non-appealable court decision is rendered in connection with all such legal proceedings, DPL cannot predict (i) the extent of the negative effect that the contract for new generation may have on DPL’s balance sheets, as well as its credit metrics, as calculated by independent rating agencies that evaluate and rate DPL and its debt issuances, (ii) the effect on DPL’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contract on the financial condition, results of operations and cash flows of DPL.

Reliability Task Force

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. DPL’s electric distribution base rate case filed with the MPSC on March 29, 2013 addresses the Grid Resiliency Task Force recommendations.

MAPP Project

On August 24, 2012, the board of PJM terminated the Mid-Atlantic Power Pathway (MAPP) project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. As of December 31, 2012, DPL’s total costs related to the MAPP project were $38 million. In a 2008 Federal Energy Regulatory Commission (FERC) order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, DPL submitted a filing to FERC seeking recovery of $38 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

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Various protests were submitted in response to DPL’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of DPL, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by DPL to be $1 million) of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. DPL believes that the FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request on behalf of DPL of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that DPL is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. DPL cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, DPL had reclassified all $38 million of capital expenditures with respect to the MAPP project to a regulatory asset. During the first quarter of 2013, DPL expensed $1 million of prudently incurred abandoned costs as a result of FERC’s disallowance noted above, resulting in a regulatory asset of $37 million as of March 31, 2013. The regulatory asset includes the costs of land, land rights, engineering and design, environmental services, and project management and administration. DPL intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land and land rights.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with FERC against DPL, Pepco and Atlantic City Electric Company (ACE), as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that DPL provides. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for DPL is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. DPL believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, DPL filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

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(8) PENSION AND OTHER POSTRETIREMENT BENEFITS

DPL accounts for its participation in its parent’s single-employer plans, Pepco Holdings’ non-contributory 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 March 31, 2013 and 2012, before intercompany allocations from the PHI Service Company, were $25 million and $26 million, respectively. DPL’s allocated share was $4 million and $6 million, respectively, for the three months ended March 31, 2013 and 2012.

In the first quarter of 2013, DPL made a discretionary tax-deductible contribution to the PHI Retirement Plan of $10 million. In the first quarter of 2012, DPL made a discretionary tax-deductible contribution to the PHI Retirement Plan of $85 million.

(9) DEBT

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement, which among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility.

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 is $750 million for PHI 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 or 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 the one month London Interbank Offered Rate 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 and other 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) with certain exceptions, a restriction on sales or other dispositions of assets, 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 credit agreement contains certain covenants and other customary agreements and requirements that, if not 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 covenants under this facility as of March 31, 2013.

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The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

At March 31, 2013 and December 31, 2012, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $635 million and $477 million, respectively. DPL’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and ACE and the portion of the total capacity being used by PHI.

Commercial Paper

DPL maintains an on-going commercial paper program to address its short-term liquidity needs. As of March 31, 2013, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

DPL had $70 million of commercial paper outstanding at March 31, 2013. The weighted average interest rate for commercial paper issued by DPL during the three months ended March 31, 2013 was 0.36% and the weighted average maturity of all commercial paper issued by DPL during the three months ended March 31, 2013 was three days.

(10) INCOME TAXES

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

	Three Months Ended March 31,
	2013					2012
	(millions of dollars)
Income tax at Federal statutory rate	$	15		35.0	%	$	12	35.0	%
Increases (decreases) resulting from:
State income taxes, net of Federal effect		2		4.7	%		2	5.7	%
Changes in estimates and interest related to uncertain and effectively settled tax positions		(1	)	(2.4	)%		—	—
Other, net		—		0.8	%		—	(0.7	)%
Income tax expense	$	16		38.1	%	$	14	40.0	%

DPL’s effective tax rates for the three months ended March 31, 2013 and 2012 were 38.1% and 40.0%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions. On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which DPL is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that it can no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded a charge of $377 million (after-tax) in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in DPL recording a $1 million interest benefit in the first quarter of 2013.

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(11) 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 limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. 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 March 31, 2013 and December 31, 2012:

	As of March 31, 2013
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)	$	—	$	1	$	1	$	(1	)	$	—
Derivative assets (non-current assets)		—		—		—		—			—
Net Derivative asset	$	—	$	1	$	1	$	(1	)	$	—

	As of December 31, 2012
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)	$	—	$	(4	)	$	(4	)	$	—	$	(4	)
Derivative liabilities (non-current liabilities)		—		—			—			—		—
Net Derivative liability	$	—	$	(4	)	$	(4	)	$	—	$	(4	)

Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), 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. All derivative assets and liabilities available to be offset under master netting arrangements were netted as of March 31, 2013 and December 31, 2012. The amount of cash collateral that was offset against these derivative positions is as follows:

	March 31, 2013			December 31, 2012
	(millions of dollars)
Cash collateral received from counterparties with the obligation to return	$	(1	)	$	—

As of March 31, 2013 and December 31, 2012, all DPL cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.

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Other Derivative Activity

DPL holds certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the balance sheets with the gain or loss for 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 derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause. For the three months ended March 31, 2013 and 2012, the net unrealized derivative gains and losses arising during the period that were deferred as Regulatory Liabilities and Regulatory Assets and the net realized losses recognized in the statements of income (through Purchased Energy and Gas Purchased expense) that were also deferred as Regulatory Assets are provided in the table below:

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
Net unrealized gains (losses) arising during the period	$	2		$	(4	)
Net realized losses recognized during the period		(4	)		(7	)

As of March 31, 2013 and December 31, 2012, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	March 31, 2013				December 31, 2012
Commodity	Quantity		Net Position		Quantity		Net Position
Natural gas (one Million British Thermal Units (MMBtu))		3,245,000		Long		3,838,000		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 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 debt 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.

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The gross fair values of DPL’s derivative liabilities with credit-risk-related contingent features as of March 31, 2013 and December 31, 2012, was zero and $4 million, respectively. As of those dates, DPL had posted no cash collateral in the normal course of business against its gross derivative liabilities, resulting in net liabilities of zero and $4 million, respectively. If DPL’s debt ratings had been downgraded below investment grade as of March 31, 2013 and December 31, 2012, DPL’s net settlement amounts would have been approximately zero and $2 million, respectively, and DPL would have been required to post collateral with the counterparties of approximately zero and $2 million, respectively. The net settlement and additional collateral amounts reflect the effect of offsetting transactions under master netting agreements.

DPL’s primary source for posting cash collateral or letters of credit is PHI’s credit facility. At March 31, 2013 and December 31, 2012, the aggregate amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries was $635 million and $477 million, respectively.

(12) 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).

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 March 31, 2013 and December 31, 2012. 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.

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	Fair Value Measurements at March 31, 2013
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)
Natural gas (c)	$	1	$	1	$	—	$	—
Executive deferred compensation plan assets
Money market funds		2		2		—		—
Life insurance contracts		1		—		—		1
	$	4	$	3	$	—	$	1
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.

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

(c) Represents natural gas swaps purchased by DPL as part of a natural gas hedging program approved by the DPSC.

	Fair Value Measurements at December 31, 2012
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 (c)	$	4	$	—	$	—	$	4
	$	4	$	—	$	—	$	4

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.

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

(c) Represents natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

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

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instruments that are valued using 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 2 executive deferred compensation plan liabilities associated with the life insurance policies represent 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 that are significant and 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 as of December 31, 2012, represent natural gas options used by DPL as part of a natural gas hedging program approved by the DPSC. DPL applies a Black-Scholes model to value its options with inputs, such as forward price curves, contract prices, contract volumes, the risk-free rate and implied volatility factors that are based on a range of historical NYMEX option prices. DPL maintains valuation policies and procedures and reviews the validity and relevance of the inputs used to estimate the fair value of its options. As of March 31, 2013, all of these contracts classified as level 3 derivative instruments have settled.

The table below summarizes the primary unobservable input used to determine the fair value of DPL’s level 3 instruments and the range of values that could be used for the input as of December 31, 2012:

Type of Instrument	Fair Value at December 31, 2012			Valuation Technique		Unobservable Input		Range
	(millions of dollars)
Natural gas options	$	(4	)		Option model		Volatility factor		1.57 – 2.00

DPL used values within this range as part of its fair value estimates. A significant change in the unobservable input within this range would have an insignificant impact on the reported fair value as of December 31, 2012.

Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by DPL for reasonableness.

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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 three months ended March 31, 2013 and 2012, are shown below:

	Three Months Ended March  31, 2013
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(4	)	$	1
Total gains (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		—			—
Purchases		—			—
Issuances		—			—
Settlements		4			—
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	—		$	1

	Three Months Ended March 31, 2012
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(15	)	$	1
Total gains (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(3	)		—
Purchases		—			—
Issuances		—			—
Settlements		6			—
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	(12	)	$	1

Other Financial Instruments

The estimated fair values of DPL’s debt instruments that are measured at amortized cost in DPL’s financial statements and the associated level of the estimates within the fair value hierarchy as of March 31, 2013 and December 31, 2012 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy 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, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt categorized as level 1 is based on actual quoted trade prices for the debt in active markets on the measurement date.

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The fair value of Long-term debt categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt in active markets, but not on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and DPL reviews the methodologies and results.

The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient.

	Fair Value Measurements at March 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	968	$	15	$	841	$	112
	$	968	$	15	$	841	$	112

(a) The carrying amount for Long-term debt is $917 million as of March 31, 2013.

	Fair Value Measurements at December 31, 2012
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	990	$	—	$	877	$	113
	$	990	$	—	$	877	$	113

(a) The carrying amount for Long-term debt is $917 million as of December 31, 2012.

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

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(13) COMMITMENTS AND CONTINGENCIES

Environmental Matters

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 generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of DPL described below at March 31, 2013 are summarized as follows:

	Transmission and Distribution		Legacy Generation  - Regulated		Other		Total
	(millions of dollars)
Beginning balance as of January 1	$	1	$	3	$	2	$	6
Accruals		—		—		—		—
Payments		—		1		—		1
Ending balance as of March 31		1		2		2		5
Less amounts in Other Current Liabilities		1		1		2		4
Amounts in Other Deferred Credits	$	—	$	1	$	—	$	1

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, based on its alleged sale of transformers to Ward Transformer, 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. The litigation is moving forward with certain “test case” defendants (not including DPL) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The district court’s order addresses only the liability of the test case defendant. DPL has concluded that a loss is reasonably possible with respect to this matter, but was unable to estimate an amount or range of reasonably possible losses to which it may be exposed. DPL does not believe that it had extensive business transactions, if any, with the Ward Transformer site.

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.

The amount of remediation costs accrued for this matter is included in the table above in the column entitled “Legacy Generation – Regulated.”

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Metal Bank Site

In March 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted DPL on behalf of itself and other federal and state trustees to request that DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Superfund Site located in Philadelphia, Pennsylvania. DPL has executed the tolling agreement and will participate in settlement discussions with the NOAA, the trustees and other PRPs. While a loss associated with this matter is reasonably possible for DPL, an estimate of the amount or range of reasonably possible loss cannot be made at this time because the matter is in its early stages and discussions with the NOAA and other parties have yet to commence; however, costs to resolve this matter are not expected to be material for DPL.

(14) 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 methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to DPL for the three months ended March 31, 2013 and 2012 were approximately $40 million and $37 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:

	Three Months Ended March  31,
	2013		2012
	(millions of dollars)
Intercompany lease transactions (a)	$	1	$	1

(a) Included in Electric revenue.

As of March 31, 2013 and December 31, 2012, DPL had the following balances on its balance sheets due to related parties:

	March 31, 2013			December 31, 2012
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(21	)	$	(19	)
Other		(1	)		(1	)
Total	$	(22	)	$	(20	)

(a) Included in Accounts Payable Due to Associated Companies.

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
Operating Revenue	$	277		$	256
Operating Expenses
Purchased energy		157			166
Other operation and maintenance		61			56
Depreciation and amortization		31			28
Other taxes		4			4
Deferred electric service costs		1			(15	)
Total Operating Expenses		254			239
Operating Income		23			17
Other Income (Expenses)
Interest expense		(17	)		(17	)
Other income		—			1
Total Other Expenses		(17	)		(16	)
Income Before Income Tax Benefit		6			1
Income Tax Benefit		(3	)		(1	)
Net Income	$	9		$	2

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2013			December 31, 2012
	(millions of dollars)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	10		$	6
Restricted cash equivalents		10			10
Accounts receivable, less allowance for uncollectible accounts of $10 million and $11 million, respectively		191			192
Inventories		30			30
Prepayments of income taxes		27			27
Income taxes receivable		112			5
Assets and accrued interest related to uncertain tax positions		10			—
Prepaid expenses and other		9			11
Total Current Assets		399			281
INVESTMENTS AND OTHER ASSETS
Regulatory assets		670			694
Prepaid pension expense		115			88
Income taxes receivable		31			133
Restricted cash equivalents		16			17
Assets and accrued interest related to uncertain tax positions		6			12
Derivative assets		8			8
Other		11			12
Total Investments and Other Assets		857			964
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment		2,820			2,771
Accumulated depreciation		(794	)		(787	)
Net Property, Plant and Equipment		2,026			1,984
TOTAL ASSETS	$	3,282		$	3,229

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2013		December 31, 2012
	(millions of dollars, except shares)
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	208	$	133
Current portion of long-term debt		108		108
Accounts payable and accrued liabilities		122		147
Accounts payable due to associated companies		17		14
Taxes accrued		20		10
Interest accrued		20		15
Other		44		47
Total Current Liabilities		539		474
DEFERRED CREDITS
Regulatory liabilities		89		102
Deferred income taxes, net		769		766
Investment tax credits		6		6
Other postretirement benefit obligations		34		34
Derivative liabilities		11		11
Other		17		18
Total Deferred Credits		926		937
LONG-TERM LIABILITIES
Long-term debt		760		760
Transition Bonds issued by ACE Funding		246		256
Total Long-Term Liabilities		1,006		1,016
COMMITMENTS AND CONTINGENCIES (NOTE 12)
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		576
Retained earnings		209		200
Total Equity		811		802
TOTAL LIABILITIES AND EQUITY	$	3,282	$	3,229

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2013			2012
	(millions of dollars)
OPERATING ACTIVITIES
Net income	$	9		$	2
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		31			28
Deferred income taxes		2			72
Changes in:
Accounts receivable		1			17
Inventories		—			(1	)
Regulatory assets and liabilities, net		(1	)		(16	)
Accounts payable and accrued liabilities		—			(8	)
Pension contributions		(30	)		(30	)
Income tax-related prepayments, receivables and payables		3			(63	)
Other assets and liabilities		8			10
Net Cash From Operating Activities		23			11
INVESTING ACTIVITIES
Investment in property, plant and equipment		(74	)		(53	)
Department of Energy capital reimbursement awards received		—			1
Net other investing activities		(2	)		—
Net Cash Used By Investing Activities		(76	)		(52	)
FINANCING ACTIVITIES
Reacquisitions of long-term debt		(10	)		(9	)
Issuances of short-term debt, net		75			—
Net other financing activities		(8	)		8
Net Cash From (Used By) Financing Activities		57			(1	)
Net Increase (Decrease) in Cash and Cash Equivalents		4			(42	)
Cash and Cash Equivalents at Beginning of Period		6			91
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	10		$	49
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes (includes payments from PHI for federal income taxes)	$	—		$	—

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

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ATLANTIC CITY ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

	Common Stock
(millions of dollars, except shares)	Shares		Par Value		Premium on Stock		Retained Earnings		Total
BALANCE, DECEMBER 31, 2012		8,546,017	$	26	$	576	$	200	$	802
Net Income		—		—		—		9		9
BALANCE, MARCH 31, 2013		8,546,017	$	26	$	576	$	209	$	811

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 consolidated financial statements prepared in accordance with GAAP have been omitted. Therefore, these consolidated financial statements should be read along with the annual consolidated financial statements included in ACE’s annual report on Form 10-K for the year ended December 31, 2012. 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 March 31, 2013, in accordance with GAAP. The year-end December 31, 2012 consolidated balance sheet included herein was derived from audited consolidated financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2013 may not be indicative of ACE’s results that will be realized for the full year ending December 31, 2013.

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, future cash flows and fair value amounts for use in asset impairment evaluations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, 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.

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Consolidation of Variable Interest Entities

ACE assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests.

ACE Power Purchase Agreements

ACE is a party to three power purchase agreements (PPAs) with unaffiliated, non-utility generators (NUGs) totaling 459 megawatts (MWs). One of the agreements ends in 2016 and the other two end in 2024. PHI was unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, ACE 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 March 31, 2013 and 2012 were approximately $54 million and $51 million, respectively, of which approximately $54 million and $50 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 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 consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

ACE Standard Offer Capacity Agreements

In April 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 generation companies to receive payments from, or require them to 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 electric distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. ACE’s share of the payments received from or the payments made to the generation companies is currently estimated to be approximately 15 percent, based on its proportionate share of the total New Jersey electric load for all EDCs. The NJBPU has ordered that ACE is obligated to distribute to its distribution customers all payments it receives from the generation companies and may recover from its distribution customers all payments it makes to the generation companies. For additional discussion about the SOCAs, see Note (6), “Regulatory Matters.”

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In May 2012, all three generation companies under the SOCAs bid into the PJM 2015-2016 capacity auction and two of the generators cleared that capacity auction. ACE recorded a derivative asset (liability) for the estimated fair value of each SOCA and recorded an offsetting regulatory liability (asset) as described in more detail in Note (10), “Derivative Instruments and Hedging Activities,” and Note (11), “Fair Value Disclosures.” FASB guidance on derivative accounting and the accounting for regulated operations would apply to ACE’s obligations under the third SOCA once the related capacity has cleared a PJM auction. The next PJM capacity auction is scheduled for May 2013. PHI has concluded that consolidation of the generation companies is not required.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were $3 million and $4 million for the three months ended March 31, 2013 and 2012, respectively.

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Balance Sheet (ASC 210)

In December 2011, the FASB issued new disclosure requirements for financial assets and financial liabilities, such as derivatives, that are subject to contractual netting arrangements. The new disclosure requirements include information about the gross exposure of the instruments and the net exposure of the instruments under contractual netting arrangements, how the exposures are presented in the financial statements, and the terms and conditions of the contractual netting arrangements. As of March 31, 2013, ACE adopted the new guidance and concluded it did not have a material impact on its consolidated financial statements.

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Joint and Several Liability Arrangements (ASC 405)

In February 2013, the FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, ACE will be required to include in its liabilities the additional amounts it expects to pay on behalf of its co-obligors, if any. ACE will also be required to provide additional disclosures including the nature of the arrangements with its co-obligors, the total amounts outstanding under the arrangements between ACE and its co-obligors, the carrying value of the liability, and the nature and limitations of any recourse provisions that would enable recovery from other entities.

The new requirements would be effective retroactively beginning on January 1, 2014, with implementation required for prior periods if joint and several liability arrangement obligations exist as of January 1, 2014. ACE is evaluating the impact of this new guidance on its consolidated financial statements.

(5) SEGMENT INFORMATION

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

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(6) REGULATORY MATTERS

Rate Proceedings

Electric Distribution Base Rates

On December 11, 2012, ACE submitted an application with the NJBPU, updated on January 4, 2013, to increase its electric distribution base rates by approximately $70.4 million (excluding sales-and-use taxes), based on a requested ROE of 10.25%. This proposed net increase was comprised of (i) a proposed increase to ACE’s distribution rates of approximately $72.1 million and (ii) a net decrease to ACE’s Regulatory Asset Recovery Charge (costs associated with deferred, NJBPU-approved expenses incurred as part of ACE’s public service obligation) in the amount of approximately $1.7 million. The requested rate increase is primarily for the purposes of continuing to implement reliability-related investments and recovering system restoration costs associated with the June 2012 derecho storm and Hurricane Sandy. An NJBPU decision is expected by the fourth quarter of 2013.

In a March 20, 2013 order, the NJBPU established a generic proceeding to evaluate the prudency of major storm event restoration costs and expenses. Each New Jersey EDC was directed to file a separate proceeding for the evaluation of these costs. Those portions of ACE’s electric base rate filing pertaining to the recovery of major storm event expenditures will be evaluated in the context of the generic proceeding. On April 9, 2013, ACE filed a petition with the NJBPU to comply with the NJBPU’s generic storm cost order. All other issues in ACE’s base rate filing remain unchanged in the electric base rate proceeding discussed above.

Update and Reconciliation of Certain Under-Recovered Balances

In February 2012, ACE submitted a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges for the New Jersey Societal Benefit Program and ACE’s uncollected accounts, and (iii) operating costs associated with ACE’s residential appliance cycling program. The filing proposed to recover the projected deferred under-recovered balance related to the NUGs of $113.8 million as of May 31, 2012 through a four-year amortization schedule. In June 2012, the NJBPU approved a stipulation of settlement signed by the parties, which provided for provisional rates that went into effect on July 1, 2012. The net impact of adjusting the charges (consisting of both the annual impact of the proposed four-year amortization of the historical under-recovered NUG balances of $127.0 million as of June 30, 2012 and the going-forward cost recovery of all the other charges for the period July 1, 2012 through May 31, 2013, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $55.3 million. The rates were deemed “provisional” because ACE’s filing was not updated for actual revenues and expenses for May and June 2012 until the March 5, 2013 petition described below was filed, after which a review by the NJBPU of the final underlying costs for reasonableness and prudence will be completed.

On March 5, 2013, ACE submitted a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program for low income customers) and ACE’s uncollected accounts, and (iii) operating costs associated with ACE’s residential appliance cycling program. The net impact of adjusting the charges updated for actual data through March 31, 2013 (consisting of both the second year impact of the stipulated four-year amortization of the historical under-recovered NUG balances and the going-forward cost recovery of all the other charges for the period June 1, 2013 through May 31, 2014, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $52.2 million. ACE expects that the final order in this proceeding will finalize the rates for the proceeding filed in February 2012. ACE has requested the NJBPU to issue a decision by the end of the second quarter of 2013.

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Standard Offer Capacity Agreements

In April 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company, as more fully described in Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – ACE Standard Offer Capacity Agreements” and Note (10), “Derivative Instruments and Hedging Activities.” ACE and the other New Jersey EDCs entered into the SOCAs under protest, arguing that the EDCs were denied due process and that the SOCAs violate certain of the requirements under the New Jersey law under which the SOCAs were established. The dispute is pending before the NJBPU and has been referred to an Administrative Law Judge for further consideration. On April 11, 2013, the Superior Court of New Jersey Appellate Division issued an order consolidating the EDCs’ state court appeal of the NJBPU order (filed by the EDCs with the Appellate Division of the New Jersey Superior Court in June 2011) with a similar challenge filed by several generators and instructing the Administrative Law Judge to complete proceedings by June 15, 2013. The matter remains pending.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the the New Jersey law under which the SOCAs were established on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In September 2012, the District Court denied motions for summary judgment filed by ACE and the other plaintiffs, as well as cross-motions filed by defendants. The litigation remains pending and trial is scheduled to be completed on or before May 8, 2013. It has not been determined when the District Court will issue a decision.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with the Federal Energy Regulatory Commission (FERC) against ACE, Potomac Electric Power Company (Pepco) and Delmarva Power & Light Company (DPL), as well as Baltimore Gas and Electric Company. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that ACE provides. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for ACE is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. ACE believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, ACE filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

(7) PENSION AND OTHER POSTRETIREMENT BENEFITS

ACE accounts for its participation in its parent’s single-employer plans, Pepco Holdings’ non-contributory 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 March 31, 2013 and 2012, before intercompany allocations from the PHI Service Company, were $25 million and $26 million, respectively. ACE’s allocated share was $5 million and $6 million, respectively, for the three months ended March 31, 2013 and 2012.

In the first quarter of 2013, ACE made a discretionary tax-deductible contribution to the PHI Retirement Plan of $30 million. In the first quarter of 2012, ACE made a discretionary tax-deductible contribution to the PHI Retirement Plan of $30 million.

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(8) DEBT

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement, which among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility.

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 is $750 million for PHI 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 or 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 the one month London Interbank Offered Rate 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 and other 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) with certain exceptions, a restriction on sales or other dispositions of assets, 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 credit agreement contains certain covenants and other customary agreements and requirements that, if not 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 covenants under this facility at March 31, 2013.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

At March 31, 2013 and December 31, 2012, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $635 million and $477 million, respectively. ACE’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and DPL and the portion of the total capacity being used by PHI.

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Commercial Paper

ACE maintains an on-going commercial paper program to address its short-term liquidity needs. As of March 31, 2013, the maximum capacity available under the program was $250 million, subject to available borrowing capacity under the credit facility.

ACE had $185 million of commercial paper outstanding at March 31, 2013. The weighted average interest rate for commercial paper issued by ACE during the three months ended March 31, 2013 was 0.37% and the weighted average maturity of all commercial paper issued by ACE during the three months ended March 31, 2013 was seven days.

Financing Activities

Bond Payments

In January 2013, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

Financing Activities Subsequent to March 31, 2013

Bond Payments

In April 2013, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

Bond Redemptions

In April 2013, ACE issued notice for optional redemption on May 30, 2013, at par plus accrued interest, of all $4.4 million outstanding weekly rate pollution control revenue refunding bonds due 2017, issued by the Pollution Control Financing Authority of Salem County, New Jersey for ACE’s benefit.

(9) INCOME TAXES

ACE’s consolidated effective tax rates for the three months ended March 31, 2013 and 2012 were (50.3)% and (100)%, respectively. The change in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions. In the first quarter of 2013, ACE recorded an interest benefit of $6 million as discussed further below. In the first quarter of 2012, ACE recorded an interest benefit as a result of the effective settlement with the Internal Revenue Service with respect to the methodology used historically to calculate deductible mixed service costs.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which ACE is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that it can no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded a charge of $377 million (after-tax) in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in ACE recording a $6 million interest benefit in the first quarter of 2013.

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(10) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would receive payments from or make payments to electric generation facilities based on (i) the difference between the fixed price in the SOCAs and the price for capacity that clears PJM and (ii) ACE’s annual proportion of the total New Jersey load relative to the other EDCs in New Jersey, which is currently estimated to be 15 percent. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because the generators cleared the 2015-2016 PJM capacity auction in May 2012. Changes in the fair value of the derivatives embedded in the SOCAs are deferred as Regulatory Assets or Regulatory Liabilities because the NJBPU has allowed full recovery from ACE’s distribution customers for all payments made by ACE, and ACE’s distribution customers would be entitled to all payments received by ACE.

As of March 31, 2013, ACE had non-current Derivative Assets of $8 million and non-current Derivative Liabilities of $11 million associated with the two SOCAs and an offsetting regulatory liability and regulatory asset, respectively, of the same amounts. As of March 31, 2013, ACE had 180 MWs of capacity in a long position, with no collateral or netting applicable to the capacity. Unrealized gains and losses associated with these capacity derivatives, which netted to an unrealized loss of zero for the three months ended March 31, 2013, have been deferred as Regulatory Liabilities and Regulatory Assets.

(11) 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).

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 March 31, 2013 and December 31, 2012. 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 March 31, 2013
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)
Capacity (c)	$	8	$	—	$	—	$	8
Cash equivalents
Treasury fund		26		26		—		—
	$	34	$	26	$	—	$	8
LIABILITIES
Derivative instruments (b)
Capacity (c)	$	11	$	—	$	—	$	11
Executive deferred compensation plan liabilities
Life insurance contracts		1		—		1		—
	$	12	$	—	$	1	$	11

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.

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

(c) Represents derivatives associated with ACE SOCAs.

	Fair Value Measurements at December 31, 2012
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)
Capacity (c)	$	8	$	—	$	—	$	8
Cash equivalents
Treasury fund		27		27		—		—
	$	35	$	27	$	—	$	8
LIABILITIES
Derivative instruments (b)
Capacity (c)	$	11	$	—	$	—	$	11
Executive deferred compensation plan liabilities
Life insurance contracts		1		—		1		—
	$	12	$	—	$	1	$	11

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.

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

(c) Represents derivatives associated with ACE SOCAs.

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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 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 that are significant and 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 represent capacity under the SOCAs entered into by ACE.

ACE used a discounted cash flow methodology to estimate the fair value of the capacity derivatives embedded in the SOCAs. ACE utilized an external valuation specialist to estimate annual zonal PJM capacity prices through the 2030-2031 auction. The capacity price forecast was based on various assumptions that impact the cost of constructing new generation facilities, including zonal load forecasts, zonal fuel and energy prices, generation capacity and transmission planning, and environmental legislation and regulation. ACE reviewed the assumptions and resulting capacity price forecast for reasonableness. ACE used the capacity price forecast to estimate future cash flows. A significant change in the forecasted prices would have a significant impact on the estimated fair value of the SOCAs. ACE employed a discount rate reflective of the estimated weighted average cost of capital for merchant generation companies since payments under the SOCAs are contingent on providing generation capacity.

The tables below summarize the primary unobservable inputs used to determine the fair value of ACE’s level 3 instruments and the range of values that could be used for those inputs as of March 31, 2013 and December 31, 2012:

Type of Instrument	Fair Value at March 31, 2013			Valuation Technique		Unobservable Input		Range
	(millions of dollars)
Capacity contracts, net	$	(3	)		Discounted cash flow		Discount rate		6% - 8%

Type of Instrument	Fair Value at December 31, 2012			Valuation Technique		Unobservable Input		Range
	(millions of dollars)
Capacity contracts, net	$	(3	)		Discounted cash flow		Discount rate		5% - 9%

ACE used values within these ranges as part of its fair value estimates. A significant change in any of the unobservable inputs within these ranges would have an insignificant impact on the reported fair value as of March 31, 2013 and December 31, 2012.

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A reconciliation of the beginning and ending balances of ACE’s fair value measurements using significant unobservable inputs (level 3) for the three months ended March 31, 2013 is shown below:

	Capacity
	Three Months Ended March 31, 2013
	(millions of dollars)
Beginning balance as of January 1	$	(3	)
Total gains (losses) (realized and unrealized):
Included in income		—
Included in accumulated other comprehensive loss		—
Included in regulatory liabilities and regulatory assets		—
Purchases		—
Issuances		—
Settlements		—
Transfers in (out) of level 3		—
Ending balance as of March 31	$	(3	)

Other Financial Instruments

The estimated fair values of ACE’s debt instruments that are measured at amortized cost in ACE’s consolidated financial statements and the associated levels of the estimates within the fair value hierarchy as of March 31, 2013 and December 31, 2012 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy 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, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt and Transition Bonds issued by ACE Funding categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt in active markets, but not on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and ACE reviews the methodologies and results.

The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient.

	Fair Value Measurements at March 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,007	$	—	$	877	$	130
Transition Bonds issued by ACE Funding (b)		327		—		327		—
	$	1,334	$	—	$	1,204	$	130

(a) The carrying amount for Long-term debt is $829 million as of March 31, 2013.

(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $285 million as of March 31, 2013.

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	Fair Value Measurements at December 31, 2012
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,016	$	—	$	884	$	132
Transition Bonds issued by ACE Funding (b)		341		—		341		—
	$	1,357	$	—	$	1,225	$	132

(a) The carrying amount for Long-term debt is $829 million as of December 31, 2012.

(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $295 million as of December 31, 2012.

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

(12) COMMITMENTS AND CONTINGENCIES

General Litigation

In September 2011, an asbestos complaint was filed in the New Jersey Superior Court, Law Division, against ACE (among other defendants) asserting claims under New Jersey’s Wrongful Death and Survival statutes. The complaint, filed by the estate of a decedent who was the wife of a former employee of ACE, alleges that the decedent’s mesothelioma was caused by exposure to asbestos brought home by her husband on his work clothes. New Jersey courts have recognized a cause of action against a premise owner in a so-called “take home” case if it can be shown that the harm was foreseeable. In this case, the complaint seeks recovery of an unspecified amount of damages for, among other things, the decedent’s past medical expenses, loss of earnings, and pain and suffering between the time of injury and death, and asserts a punitive damage claim. At this time, ACE has concluded that a loss is reasonably possible with respect to this matter, but ACE was unable to estimate an amount or range of reasonably possible loss because (i) the damages sought are indeterminate, (ii) the proceedings are in the early stages, and (iii) the matter involves facts that ACE believes are distinguishable from the facts of the “take-home” cause of action recognized by the New Jersey courts. A trial date has been set for May 20, 2013.

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Environmental Matters

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 customers of ACE, environmental clean-up costs incurred by ACE generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of ACE described below at March 31, 2013 are summarized as follows:

	Legacy Generation - Regulated
	(millions of dollars)
Beginning balance as of January 1	$	1
Accruals		—
Payments		—
Ending balance as of March 31		1
Less amounts in Other Current Liabilities		—
Amounts in Other Deferred Credits	$	1

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’s feasibility study for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million.

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, based on its alleged sale of transformers to Ward Transformer, 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. The litigation is moving forward with certain “test case” defendants (not including ACE) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The district court’s order addresses only the liability of the test case defendant. ACE has concluded that a loss is reasonably possible with respect to this matter, but ACE was unable to estimate an amount or range of reasonably possible losses to which it may be exposed. ACE does not believe that it had extensive business transactions, if any, with the Ward Transformer site.

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(13) 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 methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to ACE for the three months ended March 31, 2013 and 2012 were approximately $31 million and $28 million, respectively.

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

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
Meter reading services provided by Millennium Account Services LLC (an ACE affiliate) (a)	$	(1	)	$	(1	)

(a) Included in Other Operation and Maintenance expense.

As of March 31, 2013 and December 31, 2012, ACE had the following balances on its consolidated balance sheets due to related parties:

	March 31, 2013			December 31, 2012
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(16	)	$	(13	)
Other		(1	)		(1	)
Total	$	(17	)	$	(14	)

(a) Included in Accounts Payable Due to Associated Companies.

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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		118
Pepco		146
DPL		154
ACE		163

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

Pepco Holdings, Inc.

General Overview

PHI, a Delaware corporation incorporated in 2001, is a holding company that, through its 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). Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy savings performance contracting services, high voltage underground transmission cabling, construction and operations of combined heat and power and central energy plants and is in the process of winding down its competitive retail supply business. For additional discussion, see “Pepco Energy Services” below.

Each of Power Delivery and Pepco Energy Services constitutes a separate segment for financial reporting purposes. A third segment, Other Non-Regulated, includes the portfolio of cross-border energy lease investments held by PCI.

The following table sets forth the percentage contributions to consolidated operating revenue and consolidated operating (loss) income from continuing operations attributable to PHI segments:

	Three Months Ended March 31,
	2013			2012
Percentage of Consolidated Operating Revenue
Power Delivery		132	%		85	%
Pepco Energy Services		11	%		14	%
Other Non-Regulated		(43)	%		1	%
Corporate and Other		—	%		—	%
Percentage of Consolidated Operating (Loss) Income
Power Delivery		(52)	%		77	%
Pepco Energy Services		(1)	%		7	%
Other Non-Regulated		156	%		9	%
Corporate and Other		(3)	%		7	%
Percentage of Power Delivery Operating Revenue
Power Delivery Electric		92	%		93	%
Power Delivery Gas		8	%		7	%

Power Delivery

Power Delivery Electric consists primarily of the transmission, distribution and default supply of electricity, and Power Delivery Gas consists of the distribution and supply of natural gas. Power Delivery represents a single operating segment for financial reporting purposes.

Each utility comprising Power Delivery is a regulated public utility 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 in each jurisdiction. 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 report, these supply service obligations are referred to generally as Default Electricity Supply.

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Each of Pepco, DPL and ACE is responsible for the transmission of wholesale electricity into and across its service territory. The rates each utility is permitted to charge for the wholesale transmission of electricity are regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

The profitability of Power Delivery depends on its ability to recover costs and earn a reasonable return on its capital investments through the rates it is permitted to charge. Operating results also can be affected by economic conditions, energy prices, the impact of energy efficiency measures on customer usage of electricity and weather.

Power Delivery’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco and DPL in Maryland and of Pepco in the District of Columbia, revenue is not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer rather than a charge based upon energy usage. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from retail customers 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. A comparable revenue decoupling mechanism for DPL electricity and natural gas customers in Delaware is under consideration by the Delaware Public Service Commission (DPSC).

In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment (an adjustment equal to the amount by which revenue from distribution sales differs from the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer) is recorded representing either (i) a positive adjustment equal to the amount by which revenue from retail distribution sales falls short of the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer.

Since 2010, PHI has implemented comprehensive reliability enhancement plans which include various initiatives to improve electrical system reliability, including:

• 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 systems;

• the rejuvenation and replacement of underground residential cables;

• selective undergrounding of portions of existing above-ground primary feeder lines, where appropriate to improve reliability;

• improvements to substation supply lines; and

• enhanced vegetation management.

Power Delivery Initiatives and Activities

Smart Grid

PHI is building a “smart grid” which is designed to meet the challenges of rising energy costs, respond to concerns about the environment, improve reliability, provide timely and accurate customer information and address government energy reduction goals. A central component of the smart grid is advanced metering infrastructure (AMI), which is a system that collects, measures and analyzes energy usage data from advanced digital electric and gas meters known as smart meters. The installation of smart meters is subject to the approval of applicable state regulators. The District of Columbia Public Service

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Commission (DCPSC), Maryland Public Service Commission (MPSC) and DPSC have approved the creation of regulatory assets to defer AMI costs between rate cases, as well as the accrual of returns on the deferred costs. Thus, these costs will be recovered in the future through base rates. Approval of AMI has been deferred by the New Jersey Board of Public Utilities (NJBPU) for ACE in New Jersey.

Meter installation and activation are scheduled to be completed in the second quarter of 2013 for Pepco customers in the District of Columbia and are expected to be completed in the third quarter of 2013 for Pepco customers in Maryland. In 2012, the MPSC approved the deployment of AMI for electric customers in DPL’s Maryland service territory, and installation is scheduled to begin in the second quarter of 2013. Electric meter installation and activation are complete for DPL electric customers in Delaware; installation of smart meters for natural gas delivery customers in Delaware is ongoing.

In April 2010, PHI signed agreements to formalize $168 million in awards from the U.S. Department of Energy to support the rollout of smart grid initiatives. In the Pepco service area, $149 million was awarded for AMI, direct load control, distribution automation and communications infrastructure, while in the ACE service area, $19 million was awarded for direct load control, distribution automation and communications infrastructure. The grants effectively reduce the project costs of these initiatives. The cumulative award payments received by Pepco and ACE as of March 31, 2013 were $116 million and $13 million, respectively.

Mitigation of Regulatory Lag

An important factor in the ability of each of Pepco, DPL and ACE to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in the utility’s rate structure in order to address the shortfall in revenues due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Each of Pepco, DPL and ACE is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth.

In an effort to minimize the effects of regulatory lag, Pepco’s and DPL’s District of Columbia, Delaware and Maryland base rate case filings in 2011 each included a request for approval from the applicable state regulatory commissions of (i) a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases and (ii) the use by the applicable utility of fully forecasted test years in future base rate cases. In both the Pepco and DPL base rate case orders issued by the MPSC in 2012, the MPSC did not approve Pepco’s and DPL’s requests to implement the RIM and did not endorse the use by Pepco and DPL of fully forecasted test years in future rate cases. However, the MPSC did permit an adjustment to the rate base of Pepco and DPL to reflect the actual cost of reliability plant additions outside the test year. In the District of Columbia, the DCPSC denied Pepco’s request for approval of a RIM in 2012, and reserved final judgment on the appropriateness of the use by Pepco of a fully forecasted test year in future rate cases. In Delaware, a settlement agreement approved by the DPSC in DPL’s electric distribution base rate case did not include approval of a RIM or the use of fully forecasted test years in future DPL rate cases, but it did provide that the parties will meet and discuss alternate regulatory methodologies for the mitigation of regulatory lag.

Each of PHI’s utility subsidiaries will continue to seek cost recovery from applicable public service commissions to reduce the effects of regulatory lag. There can be no assurance that any attempts by PHI’s utility subsidiaries to mitigate regulatory lag will be approved, or that even if approved, the cost recovery mechanisms will fully mitigate the effects of regulatory lag. Until such time as any cost recovery mechanisms are approved, PHI’s utility subsidiaries plan to file rate cases at least annually in an effort to align more closely the revenue and cash flow levels of PHI’s utility subsidiaries with other operation and maintenance spending and capital investments. Pepco filed electric distribution base rate cases in November 2012 in Maryland and in March 2013 in the District of Columbia. DPL filed electric distribution base rate cases in both Delaware and Maryland in March 2013, and filed a natural gas distribution case in December 2012. ACE filed an electric distribution base rate case in December 2012.

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In their respective electric distribution base rate cases filed in Maryland, each of Pepco and DPL include a proposed three-year Grid Resiliency Charge rider intended to reduce regulatory lag. This rider provides for recovery of costs associated with Pepco’s and DPL’s respective plans to accelerate investments in electric distribution infrastructure in a condensed timeframe. See Note (7), “Regulatory Matters – Rate Proceedings,” to the consolidated financial statements of PHI for more information about these base rate cases.

MAPP Project

On August 24, 2012, the board of PJM terminated the MAPP project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system.

PHI had included in its five-year projected capital expenditures $205 million of MAPP-related expenditures for the period from 2012 to 2016. PHI has updated its five-year projected capital expenditures to remove MAPP-related expenditures to reflect the PJM decision. As of March 31, 2013, PHI’s total costs related to the MAPP project were $102 million. In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, PHI submitted a filing to FERC seeking recovery over a period of five years of $88 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

Various protests were submitted in response to PHI’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of Pepco and DPL, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by PHI to be $2 million) of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. PHI believes that the FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that PHI is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. PHI cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, PHI had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories, for use on other projects, and reclassified the remaining $88 million of capital expenditures to a regulatory asset. During the first quarter of 2013, PHI further transferred an additional $2 million of materials to inventories, for use on other projects, and expensed $2 million of abandoned costs as a result of FERC’s disallowance noted above, resulting in a regulatory asset of $84 million as of March 31, 2013. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. PHI intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

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Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with FERC against Pepco, DPL and ACE, as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s utilities provide. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. PHI, Pepco, DPL and ACE believe the allegations in this complaint are without merit and are vigorously contesting it. On April 3, 2013, Pepco, DPL and ACE filed their answer to this complaint, requesting that FERC dismiss the complaint against them on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

Pepco Energy Services

Since 2010, Pepco Energy Services has been focused on growing its energy savings performance contracting services business in the federal, state and local government markets. Activity in the state and local government markets, which are Pepco Energy Services’ largest markets, slowed significantly in 2012, due to, among other factors, lower energy prices that have lessened the economic benefits of energy savings projects and the reluctance of state and local governments to incur new debt associated with these projects. As a result of the slowdown, Pepco Energy Services believes that new business in these markets will remain challenged for the foreseeable future. Consequently, Pepco Energy Services reduced resources and personnel, limited geographic expansion in the energy savings services business and has refocused its existing resources on developing business in the federal government market and continuing to pursue combined heat and power projects.

PHI guarantees the obligations of Pepco Energy Services under certain of its energy savings performance, combined heat and power and construction contracts. At March 31, 2013, PHI’s guarantees of Pepco Energy Services’ obligations under these contracts totaled $196 million.

Pepco Energy Services also has historically been engaged in the business of providing retail electric and natural gas supply services, consisting of the sale of electricity, including electricity from renewable resources, primarily to commercial, industrial and government customers located in the mid-Atlantic and northeastern regions of the United States, as well as Texas and Illinois, and the sale of natural gas to customers located primarily in the mid-Atlantic region. In December 2009, PHI announced that it will wind down the retail electric and natural gas supply components of the Pepco Energy Services business.

To effectuate the wind-down of the retail electric supply business, Pepco Energy Services is continuing to fulfill all of its commercial and regulatory obligations and perform its customer service functions to ensure that it meets the needs of its existing customers, but is not entering into any new retail electric supply contracts. Also, as discussed below, on March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all of the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, gas inventory and derivative contracts. Pepco Energy Services completed the transaction on April 1, 2013.

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On April 2, 2013, Pepco Energy Services received $8 million of cash collateral that it had previously pledged against derivative contracts in its retail natural gas supply business as part of the transaction.

Operating revenues related to the retail electric supply business for the three months ended March 31, 2013 and 2012 were $41 million and $108 million, respectively, and operating income for the same periods was $1 million and $6 million, respectively. PHI expects the operating results of the retail electric supply business, excluding the effects of unrealized mark-to-market gains or losses on derivatives contracts, to have immaterial losses in 2013 and 2014. Substantially all of Pepco Energy Services’ retail electric customer obligations will be fully performed by June 1, 2014. PHI is reviewing strategic alternatives to accelerate into 2013 the completion of the wind-down of its remaining portfolio of retail electric contracts.

In connection with the operation of the retail electric supply business as of March 31, 2013, Pepco Energy Services had net collateral pledged to counterparties, primarily in connection with the instruments it uses to hedge commodity price risk, of approximately $6 million. The collateral pledged as of March 31, 2013 included less than $1 million in the form of letters of credit and $5 million posted in cash. Pepco Energy Services does not expect to have any such collateral obligations beyond June 1, 2014.

Pepco Energy Services’ remaining businesses will not be affected by the wind-down of the retail electric supply business.

Other Non-Regulated

Cross-Border Energy Lease Investments

Through its subsidiary Potomac Capital Investment Corporation and its subsidiaries (PCI), PHI maintains a portfolio of cross-border energy lease investments with a net investment value at March 31, 2013 of $869 million. These investments comprise the majority of the “Other Non-Regulated” segment. As discussed in Note (15), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments,” PHI is involved in ongoing litigation with the IRS concerning certain benefits associated with its cross-border energy leases. On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that its tax position with respect to the benefits associated with its cross-border energy leases no longer meets the more likely than not standard of recognition for accounting purposes, and the Other Non-Regulated segment recorded a non-cash charge of $323 million (after-tax) in the first quarter of 2013, consisting of the following components:

• A non-cash pre-tax charge of $373 million ($307 million after-tax) to reduce the carrying value of these cross-border energy lease investments under Financial Accounting Standards Board (FASB) guidance on leases (Accounting Standards Codification (ASC 840)). This pre-tax charge has been recorded in the consolidated statement of income as a reduction in Other Operating revenue.

• A non-cash charge of $16 million after-tax to reflect the anticipated additional net interest expense under FASB guidance for income taxes (ASC 740), related to estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed. This after-tax charge has been recorded in the Consolidated Statement of Income as an increase in income tax expense. The after-tax interest charge for PHI on a consolidated basis was $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in the recognition of a $12 million interest benefit for the Power Delivery segment and interest expense of $16 million and $66 million for the Other Non-Regulated and Corporate and Other segments, respectively.

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In March 2013, PHI began to pursue the early termination of its remaining cross-border energy lease investments with its lessees. During April 2013, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the six lease investments and one of the leases included in a second lease investment. Upon closing, PHI received aggregate net cash proceeds of $168 million (net of aggregate termination payments of $804 million used to retire the non-recourse debt associated with the terminated leases) and expects to record a net pre-tax loss of approximately $27 million in the second quarter of 2013, representing the excess of the carrying value of the terminated leases over the net cash proceeds received. PHI estimates that the early termination of the remaining cross-border energy lease investments could be accomplished during 2013. The aggregate financial impact of the early termination of the remaining cross-border energy lease investments is not determinable at this time, but management believes that any gains or losses incurred in the aggregate will not be material; however, there may be individual lease terminations that result in offsetting material gains and losses.

Further, the earnings from the cross-border energy leases represent a substantial portion of the Other Non-Regulated segment’s earnings and liquidation of the leases would reduce significantly the earnings of the segment. For additional information concerning these cross-border energy lease investments, see Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust,” and Note (15), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments” to the consolidated financial statements of PHI.

Other Operations

Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to both Consolidated Edison’s cross-border lease transaction and another taxpayer’s structured transactions, (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represents a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI will be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI has established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013.

Discontinued Operations

On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all of the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, gas inventory and derivative contracts. Pepco Energy Services completed the transaction on April 1, 2013. The agreement eliminated the retail natural gas supply business from the ongoing operations of Pepco Energy Services effective April 1, 2013 and Pepco Energy Services will not have significant continuing involvement in the retail natural gas supply business thereafter.

On April 2, 2013, Pepco Energy Services received $8 million of cash collateral that it had previously pledged against derivative contracts in its retail natural gas supply business after it novated the derivative contracts as part of the agreement to transfer its retail natural gas supply business on April 1, 2013.

The operations of Pepco Energy Services’ retail natural gas supply business are being accounted for as a discontinued operation and are no longer a part of the Pepco Energy Services segment for financial reporting purposes.

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Earnings Overview

Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012

Net (loss) income for the three months ended March 31, 2013 and 2012, by operating segment, is set forth in the table below (in millions of dollars):

	2013			2012		Change
Power Delivery	$	58		$	47	$	11
Pepco Energy Services		3			5		(2	)
Other Non-Regulated		(421	)		10		(431	)
Corporate and Other		(70	)		1		(71	)
Net (Loss) Income from Continuing Operations		(430	)		63		(493	)
Discontinued Operations		—			5		(5	)
Total PHI Net (Loss) Income	$	(430	)	$	68	$	(498	)

Net loss from continuing operations for the three months ended March 31, 2013 was $430 million, or $1.82 per share, compared to net income from continuing operations of $63 million, or $0.28 per share, for the three months ended March 31, 2012.

Net loss from continuing operations for the three months ended March 31, 2013 included the charges set forth below in the Other Non-Regulated and Corporate and Other operating segments, which are presented, where applicable, net of related federal and state income taxes and are in millions of dollars:

Charge to reduce the carrying value of PCI’s cross-border energy lease investments ($373 million pre-tax)	$	307
Charge to reflect the anticipated additional interest expense on estimated federal and state income tax obligations allocated to the Other Non-Regulated and the Corporate and Other Segments (as if each were a separate taxpayer) resulting from the change in assessment of the tax benefits associated with the cross-border energy lease investments ($127 million pre-tax)	$	82
Charge to establish valuation allowances related to certain PCI deferred tax assets	$	101

Excluding the items listed above for the three months ended March 31, 2013, net income from continuing operations would have been $60 million, or $0.25 per share. 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).

Net income from discontinued operations was zero for the three months ended March 31, 2013 and $5 million, or $0.02 per share, for the three months ended March 31, 2012.

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Discussion of Operating Segment Net Income Variances:

Power Delivery’s $11 million increase in earnings was primarily due to the following:

• An increase of $8 million from electric distribution base rate increases (Pepco in the District of Columbia and Maryland, DPL in Maryland and Delaware, and ACE in New Jersey).

• An increase of $7 million due to higher sales from colder weather.

• An increase of $4 million associated with ACE BGS, primarily attributable to an increase in unbilled revenue.

• An increase of $1 million associated with slightly higher interest benefits recorded in 2013 related to uncertain and effectively settled tax positions.

• A decrease of $5 million due to higher operation and maintenance expenses, primarily associated with incremental winter storm restoration costs, employee-related costs and the write-off of disallowed MAPP and associated transmission project costs, partially offset by the allowed recovery of certain customer service costs incurred in 2011 and 2012 (in accordance with an MPSC order).

• A decrease of $2 million due to higher interest expense resulting from an increase in outstanding debt.

• A decrease of $2 million due to lower transmission revenue related to a less favorable FERC formula rate true-up and the impact of peak load adjustments, partially offset by higher rates related to increases in transmission plant investment.

Other Non-Regulated’s $431 million decrease in earnings was primarily due to the following:

• A charge of $323 million related to a change in assessment regarding the tax benefits related to the cross-border energy lease investments, consisting of a $307 million charge to reduce the carrying value of the investments and a $16 million charge to reflect the anticipated additional interest expense related to the change in PCI’s estimated federal and state income tax obligations as if it were a separate taxpayer.

• A charge of $101 million to establish valuation allowances against certain PCI deferred tax assets.

Corporate and Other’s $71 million decrease in earnings was primarily due to the following:

• An after-tax charge of $66 million to reflect the anticipated additional interest expense allocated to the Corporate and Other segment related to changes in PHI’s consolidated estimated federal and state income tax obligations resulting from the change in assessment regarding the tax benefits related to the cross-border energy lease investments.

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Consolidated Results of Operations

The following results of operations discussion compares the three months ended March 31, 2013 to the three months ended March 31, 2012. 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:

	2013			2012			Change
Power Delivery	$	1,124		$	1,055		$	69
Pepco Energy Services		97			178			(81	)
Other Non-Regulated		(368	)		13			(381	)
Corporate and Other		(1	)		(4	)		3
Total Operating Revenue	$	852		$	1,242		$	(390	)

Power Delivery Business

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

	2013		2012		Change
Regulated T&D Electric Revenue	$	491	$	452	$	39
Default Electricity Supply Revenue		531		512		19
Other Electric Revenue		17		17		—
Total Electric Operating Revenue		1,039		981		58
Regulated Gas Revenue		73		65		8
Other Gas Revenue		12		9		3
Total Gas Operating Revenue		85		74		11
Total Power Delivery Operating Revenue	$	1,124	$	1,055	$	69

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 FERC-approved formula methodology.

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. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy. Default Electricity Supply Revenue also includes revenue from non-bypassable transition bond charges (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 Transition Bonds issued by ACE Funding, 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.

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

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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

	2013		2012		Change
Regulated T&D Electric Revenue
Residential	$	184	$	162	$	22
Commercial and industrial		216		201		15
Transmission and other		91		89		2
Total Regulated T&D Electric Revenue	$	491	$	452	$	39

	2013		2012		Change
Regulated T&D Electric Sales (Gigawatt hours (GWh))
Residential		4,715		4,195		520
Commercial and industrial		7,120		7,081		39
Transmission and other		70		68		2
Total Regulated T&D Electric Sales		11,905		11,344		561

	2013		2012		Change
Regulated T&D Electric Customers (in thousands)
Residential		1,643		1,640		3
Commercial and industrial		198		198		—
Transmission and other		2		2		—
Total Regulated T&D Electric Customers		1,843		1,840		3

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 activities in the region include banking and other professional services, government, insurance, real estate, shopping malls, casinos, stand alone construction and tourism.

• Industrial activities in the region include chemical, glass, pharmaceutical, steel manufacturing, food processing and oil refining.

Regulated T&D Electric Revenue increased by $39 million primarily due to:

• An increase of $16 million due to distribution rate increases (Pepco in the District of Columbia effective October 2012, and in Maryland effective July 2012; DPL in Maryland and Delaware effective July 2012; and ACE effective November 2012).

• An increase of $11 million primarily due to a Renewable Portfolio Surcharge in Delaware effective June 2012 (which is substantially offset by corresponding increases in Fuel and Purchased Energy and Depreciation and Amortization).

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• An increase of $5 million primarily due to a rate increase in the New Jersey Societal Benefit Charge (related to the New Jersey Societal Benefit Program, a public interest program for low income customers) effective July 2012 (which is offset in Deferred Electric Service Costs).

• An increase of $5 million due to higher sales as a result of colder weather during the 2013 winter months, as compared to 2012.

• An increase of $2 million in transmission revenue primarily attributable to higher capacity revenue as a result of expanding Maryland demand-side management programs (which is substantially offset by a corresponding increase in Depreciation and Amortization).

• An increase of $2 million due to higher ACE non-weather related average residential, commercial and industrial customer usage.

• An increase of $1 million due to EmPower Maryland (a demand side management program) rate increases in February 2012 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

The aggregate amount of these increases was partially offset by a decrease of $4 million in transmission revenue primarily due to a less favorable FERC formula rate true-up and a peak-load decrease effective January 2013.

Default Electricity Supply

	2013		2012		Change
Default Electricity Supply Revenue
Residential	$	375	$	358	$	17
Commercial and industrial		124		130		(6	)
Other		32		24		8
Total Default Electricity Supply Revenue	$	531	$	512	$	19

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

	2013		2012		Change
Default Electricity Supply Sales (GWh)
Residential		3,818		3,578		240
Commercial and industrial		1,255		1,393		(138	)
Other		20		15		5
Total Default Electricity Supply Sales		5,093		4,986		107

	2013		2012		Change
Default Electricity Supply Customers (in thousands)
Residential		1,354		1,426		(72	)
Commercial and industrial		127		135		(8	)
Other		—		—		—
Total Default Electricity Supply Customers		1,481		1,561		(80	)

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Default Electricity Supply Revenue increased by $19 million primarily due to:

• An increase of $36 million due to higher sales as a result of colder weather during the 2013 winter months, as compared to 2012.

• A net increase of $9 million due to higher DPL and ACE non-weather related average residential customer usage, partially offset by lower Pepco residential and commercial customer usage.

• An increase of $7 million in wholesale energy and capacity resale revenues primarily due to higher market prices for the resale of electricity and capacity purchased from NUGs.

• An increase of $2 million due to higher Pepco revenue from transmission enhancement credits.

The aggregate amount of these increases was partially offset by:

• A decrease of $30 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

• A net decrease of $5 million as a result of lower Pepco and DPL Default Electricity Supply rates, partially offset by higher ACE rates.

Total Default Electricity Supply Revenue for the three months ended March 31, 2013 includes an increase of $6 million in unbilled revenue attributable to ACE’s BGS ($4 million increase in net income), primarily due to higher non-weather related average customer usage and higher weather related sales during the unbilled revenue period at March 31, 2013 as compared to the corresponding period in 2012. Under the BGS terms approved by the NJBPU, ACE’s BGS unbilled revenue is not included in the deferral calculation until it is billed to customers, and therefore has an impact on the results of operations in the period during which it is accrued.

Regulated Gas

	2013		2012		Change
Regulated Gas Revenue
Residential	$	48	$	43	$	5
Commercial and industrial		22		19		3
Transportation and other		3		3		—
Total Regulated Gas Revenue	$	73	$	65	$	8

	2013		2012		Change
Regulated Gas Sales (million cubic feet)
Residential		4,072		3,045		1,027
Commercial and industrial		2,061		1,553		508
Transportation and other		2,432		2,129		303
Total Regulated Gas Sales		8,565		6,727		1,838

	2013		2012		Change
Regulated Gas Customers (in thousands)
Residential		115		114		1
Commercial and industrial		10		10		—
Transportation and other		—		—		—
Total Regulated Gas Customers		125		124		1

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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 as follows:

• Commercial activities in the region include banking and other professional services, government, insurance, real estate, shopping malls and stand alone construction.

• Industrial activities in the region include chemical and pharmaceutical.

Regulated Gas Revenue increased by $8 million primarily due to:

• An increase of $17 million due to higher sales primarily as a result of colder weather during the winter months of 2013, as compared to 2012.

• An increase of $5 million due to higher non-weather related average commercial and residential customer usage.

The aggregate amount of these increases was partially offset by a decrease of $13 million due to a Gas Cost Rate (GCR) decrease effective November 2012.

Other Gas Revenue

Other Gas Revenue increased by $3 million primarily due to higher average prices and higher volumes for off-system sales to electric generators and gas marketers.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased by $81 million primarily due to:

• A decrease of $65 million due to lower retail supply sales volume primarily attributable to the ongoing wind-down of the retail electric business.

• A decrease of $9 million due to decreased energy services construction activities.

• A decrease of $8 million due to lower generation and capacity revenues attributable to the deactivation of the remaining generation facilities in the second quarter of 2012.

Other Non-Regulated

Other Non-Regulated’s $381 million decrease in operating revenue was primarily due to a non-cash charge of $373 million recorded in the first quarter of 2013 to reflect a change in PHI’s current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments. For further discussion of PHI’s cross-border energy lease investments, see Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust,” and Note (15), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI.

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:

	2013		2012			Change
Power Delivery	$	562	$	543		$	19
Pepco Energy Services		78		146			(68	)
Corporate and Other		—		(1	)		1
Total	$	640	$	688		$	(48	)

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Power Delivery

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 increased by $19 million primarily due to:

• An increase of $30 million due to higher electricity sales primarily as a result of colder weather during the 2013 winter months, as compared to 2012.

• An increase of $9 million in deferred electricity expense primarily due to a Renewable Portfolio Surcharge in Delaware effective June 2012 (which is substantially offset by corresponding increases in Regulated T&D Electric Revenue).

• An increase of $4 million in the cost of gas purchases for on-system sales as a result of higher average gas prices and higher volumes purchased.

• An increase of $4 million in the cost of gas purchases for off-system sales as a result of higher average gas prices and higher volumes purchased.

• An increase of $2 million in deferred electricity expense primarily due to lower Pepco Default Electricity Supply rates, which resulted in a higher rate of recovery of Default Electricity Supply costs.

The aggregate amount of these increases was partially offset by:

• A decrease of $24 million primarily due to customer migration to competitive suppliers.

• A net decrease of $5 million due to lower average electricity costs under Pepco and ACE Default Electricity Supply contracts, partially offset by higher DPL costs.

Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased by $68 million primarily due to:

• A decrease of $60 million due to lower volumes of electricity purchased to serve decreased retail electricity sales volumes as a result of the ongoing wind-down of the retail electric supply business.

• A decrease of $7 million primarily due to lower energy services construction activity.

Other Operation and Maintenance

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

	2013			2012			Change
Power Delivery	$	231		$	224		$	7
Pepco Energy Services		14			17			(3	)
Corporate and Other		(15	)		(17	)		2
Total	$	230		$	224		$	6

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Power Delivery

Other Operation and Maintenance expense for Power Delivery increased by $7 million primarily due to:

• An increase of $5 million in incremental preparation and restoration costs associated with a winter storm in March 2013.

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

• An increase of $3 million associated with the write-off of disallowed MAPP and associated transmission project costs.

The aggregate amount of these increases was partially offset by:

• A decrease of $3 million due to the deferral of certain customer service costs incurred in 2011 and 2012 that had been previously charged to Other Operation and Maintenance expense. The deferral was recorded in accordance with an MPSC order issued in January 2013 authorizing the establishment of a regulatory asset for the recovery of these costs.

• A decrease of $3 million in other customer service costs.

Pepco Energy Services

Other Operation and Maintenance expense for Pepco Energy Services decreased by $3 million primarily due to:

• A decrease of $2 million in contractual costs due to the deactivation of its generating facilities in the second quarter of 2012.

• A decrease of $1 million in personnel costs in its energy savings services business primarily due to a reduction in the number of employees in 2012.

Depreciation and Amortization

Depreciation and Amortization expense increased by $2 million to $112 million in 2013 from $110 million in 2012 primarily due to:

• An increase of $3 million in amortization of regulatory assets primarily due to EmPower Maryland surcharge rate increases effective February 2012 and expanding Demand Side Management Programs (which are substantially offset by corresponding increases in Regulated T&D Electric Revenue).

• An increase of $2 million in amortization of regulatory costs related to recoverable storm costs and rate case costs.

• An increase of $2 million in amortization of stranded costs primarily as the result of higher revenue due to higher sales for the ACE Transition Bond Charge and Market Transition Charge Tax (revenue ACE receives and pays to ACE Funding to recover income taxes associated with Transition Bond Charge revenue), which is partially offset in Default Electricity Supply Revenue.

The aggregate amount of these increases was partially offset by:

• A decrease of $4 million primarily due to the deactivation of Pepco Energy Services generating facilities in the second quarter of 2012.

• A decrease of $1 million due to lower depreciation rates, partially offset by utility plant additions.

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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 $16 million to an expense of $1 million in 2013 as compared to an expense reduction of $15 million in 2012 primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply and New Jersey Societal Benefit Programs revenue rates and lower electricity supply costs.

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $2 million to a net expense of $59 million in 2013 from a net expense of $57 million in 2012. The increase reflects a $2 million increase in interest expense primarily associated with higher long-term debt and lower capitalized interest.

Income Tax Expense

PHI’s income tax expense increased by $124 million to $135 million in 2013 from $11 million in 2012. PHI’s consolidated effective tax rates for the three months ended March 31, 2013 and 2012 were (45.8)% and 14.9%, respectively.

The negative effective tax rate in the first quarter of 2013 occurred as a result of recording $67 million of changes in estimates and interest related to uncertain and effectively settled tax positions, primarily associated with the cross-border energy lease investments (as further discussed in Note (8), “Leasing Activities,” to the consolidated financial statements of PHI included herein) and the recognition of a $64 million charge primarily for the tax consequences associated with PHI’s change in intent regarding foreign investment opportunities available at the end of the full lease terms of the cross-border energy lease investments.

The negative effective tax rate in the first quarter of 2013 further resulted from the establishment of valuation allowances of $101 million against certain deferred tax assets in PHI’s Other Non-Regulated segment. Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to both Consolidated Edison’s cross-border lease transaction (as discussed in Note (8), “Leasing Activities,” to the consolidated financial statements of PHI included herein) and another taxpayer’s structured transactions, (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represents a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI will be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI has established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013.

In 2012, PHI recorded tax benefits of $13 million for changes in estimates and interest related to uncertain and effectively settled tax positions primarily due to the effective settlement with the IRS in the first quarter of 2012 with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position in Pepco.

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Discontinued Operations

For the three months ended March 31, 2013 and 2012, Income from Discontinued Operations, Net of Income Taxes, was zero and $5 million, respectively. The decrease in the Income from Discontinued Operations, Net of Income Taxes, is primarily the result of the recognition of $4 million of pre-tax unrealized derivative losses ($2 million after-tax) during the three months ended March 31, 2013, that previously were included in Accumulated Other Comprehensive Loss (AOCL). In the first quarter of 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all of the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, gas inventory and derivative contracts. When the agreement was entered into, PHI determined that the hedged forecasted purchases of supply for retail natural gas customers were probable not to occur and accordingly, the derivatives no longer qualified for cash flow hedge accounting. As a result, the derivative losses that had been previously recorded in AOCL were reclassified into income in the first quarter of 2013.

Capital Resources and Liquidity

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

Working Capital

At March 31, 2013, PHI’s current assets on a consolidated basis totaled $1.5 billion and its consolidated current liabilities totaled $2.9 billion, resulting in a working capital deficit of $1.4 billion. PHI expects the working capital deficit at March 31, 2013 to be funded during 2013 in part through cash flows from operations, proceeds from the early termination of PHI’s cross-border energy lease investments and from the issuance of long-term debt. At December 31, 2012, PHI’s current assets on a consolidated basis totaled $1.3 billion and its current liabilities totaled $2.5 billion, for a working capital deficit of $1.2 billion. The increase of $86 million in the working capital deficit from December 31, 2012 to March 31, 2013 was primarily due to an increase in short-term debt and an increase in liabilities and accrued interest related to uncertain tax positions.

At March 31, 2013, PHI’s consolidated cash and cash equivalents totaled $125 million, which consisted of cash and uncollected funds but excluded current Restricted Cash Equivalents (cash that is available to be used only for designated purposes) that totaled $10 million. At December 31, 2012, PHI’s consolidated cash and cash equivalents totaled $25 million, which consisted of cash and uncollected funds but excluded current Restricted Cash Equivalents that totaled $10 million.

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

	As of March 31, 2013
	(millions of dollars)
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	—	$	128
Commercial Paper		408		—		70		185		—		—		663
Term Loan Agreement		250		—		—		—		—		—		250
Total Short-Term Debt	$	658	$	—	$	175	$	208	$	—	$	—	$	1,041
Current Portion of Long-Term Debt and Project Funding	$	—	$	200	$	250	$	69	$	39	$	11	$	569

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	As of December 31, 2012
	(millions of dollars)
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	—	$	128
Commercial Paper		264		231		32		110		—		—		637
Term Loan Agreement		200		—		—		—		—		—		200
Total Short-Term Debt	$	464	$	231	$	137	$	133	$	—	$	—	$	965
Current Portion of Long-Term Debt and Project Funding	$	—	$	200	$	250	$	69	$	39	$	11	$	569

Commercial Paper

PHI, Pepco, DPL and ACE maintain commercial paper programs to address short-term liquidity needs. As of March 31, 2013, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $250 million, respectively, subject to available borrowing capacity under the credit facility.

PHI, DPL and ACE had $408 million, $70 million and $185 million, respectively, of commercial paper outstanding at March 31, 2013. Pepco had no commercial paper outstanding at March 31, 2013. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during the three months ended March 31, 2013 was 0.76%, 0.38%, 0.36% and 0.37%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during the three months ended March 31, 2013 was ten, seven, three and seven days, respectively.

Financing Activity During the Three Months Ended March 31, 2013

Equity Forward Transaction

During 2012, PHI entered into an equity forward transaction in connection with a public offering of PHI common stock. Pursuant to the terms of this transaction, a forward counterparty borrowed 17,922,077 shares of PHI’s common stock from third parties and sold them to a group of underwriters for $19.25 per share, less an underwriting discount equal to $0.67375 per share. Under the terms of the equity forward transaction, upon physical settlement thereof, PHI was required to issue and deliver the shares of PHI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $18.57625 per share at the time the equity forward transaction was entered into and was subject to reduction from time to time in accordance with the terms of the equity forward transaction. On February 27, 2013, PHI physically settled the equity forward at the then applicable forward sale price of $17.39. The proceeds of approximately $312 million were used to repay outstanding commercial paper, a portion of which had been issued in order to make capital contributions to the utilities, and for general corporate purposes.

Term Loan Agreement

On March 28, 2013, PHI entered into a $250 million term loan agreement, pursuant to which PHI has borrowed (and may not re-borrow) $250 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the London Interbank Offered Rate (LIBOR) with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.875%. PHI’s Eurodollar borrowings under the loan agreement may be converted into floating rate loans under certain circumstances, and, in that event, for so long as any loan remains a floating rate loan, interest would accrue on that loan at a rate per year equal to (i) the highest of (a) the prevailing prime rate, (b) the federal funds effective rate plus 0.5%, or (c) the one-month Eurodollar rate plus 1%, plus (ii) a margin of

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0.875%. As of March 31, 2013, outstanding borrowings under the loan agreement bore interest at an annual rate of 1.09%, which is subject to adjustment from time to time. All borrowings under the loan agreement are unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before March 27, 2014. PHI used the net proceeds of the loan under the loan agreement to repay the outstanding $200 million term loan made in 2012, and for general corporate purposes.

Under the terms of the term loan agreement, PHI must maintain compliance with specified covenants, including (i) the requirement that PHI maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the loan 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 permitted sales and dispositions, and (iii) a restriction on the incurrence of liens (other than liens permitted by the loan agreement) on the assets of PHI or any of its significant subsidiaries. The loan agreement does not include any rating triggers. PHI was in compliance with all covenants under this agreement as of March 31, 2013.

Bond Issuances

In March 2013, Pepco issued $250 million of 4.15% first mortgage bonds due March 15, 2043. These bonds were issued under a Mortgage and Deed of Trust and are secured thereunder by a first lien, subject to certain leases, permitted liens and other exceptions, on substantially all of Pepco’s properties. Net proceeds from the issuance of the long-term debt were used to repay Pepco’s outstanding commercial paper that was issued to temporarily fund capital expenditures, provide working capital and for general corporate purposes.

Bond Payments

In January 2013, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement, which, among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility.

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 is $750 million for PHI 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 or 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.

For additional discussion of the Credit Facility, see Note (10), “Debt,” to the consolidated financial statements of PHI.

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Cash and Credit Facility Available as of March 31, 2013

	Consolidated PHI		PHI Parent		Utility Subsidiaries
	(millions of dollars)
Credit Facility (Total Capacity)	$	1,500	$	750	$	750
Term Loan Agreement		250		250		—
Subtotal		1,750		1,000		750
Less: Credit Facility/Term Loan Agreement Borrowings		250		250		—
Letters of Credit issued		2		2		—
Commercial Paper outstanding		663		408		255
Remaining Credit Facility Available		835		340		495
Cash Invested in Money Market Funds and on hand (a)		140		—		140
Total Cash and Credit Facility Available	$	975	$	340	$	635

(a) Includes Cash and Cash Equivalents reported on PHI’s consolidated balance sheet of $125 million.

Financing Activities Subsequent to March 31, 2013

Bond Payments

In April 2013, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

Bond Redemptions

In April 2013, ACE issued notice for optional redemption on May 30, 2013, at par plus accrued interest, of all $4.4 million outstanding weekly rate pollution control revenue refunding bonds due 2017, issued by the Pollution Control Financing Authority of Salem County, New Jersey for ACE’s benefit.

Collateral Requirements of Pepco Energy Services

In the ordinary course of its retail electric supply business, which is in the process of being wound down, Pepco Energy Services entered 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.

As of March 31, 2013, Pepco Energy Services had posted net cash collateral of $5 million and letters of credit of less than $1 million associated with its retail electric business. At December 31, 2012, Pepco Energy Services had posted net cash collateral of $14 million and letters of credit of less than $1 million associated with its retail electric business.

At March 31, 2013 and December 31, 2012, the amount of cash, plus borrowing capacity under PHI’s credit facility available to meet the future liquidity needs of Pepco Energy Services, totaled $340 million and $384 million, respectively.

PHI’s Cross-Border Energy Lease Investments

PHI has an ongoing dispute with the IRS regarding the appropriateness of certain significant income tax benefits claimed by PHI related to its cross-border energy lease investments beginning with its 2001 federal income tax return. In the first quarter of 2013, PHI estimated that, in the event the IRS were to be fully successful in its challenge to PHI’s tax position on the cross-border energy leases, PHI would have been obligated to pay $192 million in additional federal taxes and $50 million of interest on the additional federal taxes, totaling $242 million as of March 31, 2013. The estimate of additional federal taxes due

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includes PHI’s estimate of the expected resolution of other uncertain and effectively settled tax positions unrelated to the leases, the carrying back or carrying forward of any existing net operating losses, and the application of certain amounts on deposit with the IRS.

In order to mitigate PHI’s ongoing interest costs associated with the $242 million estimate of additional taxes and interest, PHI made a $242 million deposit with the IRS for the estimated additional taxes and related interest in the first quarter of 2013. This deposit was funded from then currently available sources of liquidity and short-term borrowings. In March 2013, PHI began to pursue the early termination of its remaining cross-border energy lease investments, which had a net carrying value of approximately $869 million as of March 31, 2013. The liquidation proceeds could be used to repay any borrowings utilized to fund the deposit discussed above. During April 2013, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the six lease investments and one of the leases included in a second lease investment. Upon closing, PHI received aggregate net cash proceeds of $168 million (net of aggregate termination payments of $804 million used to retire the non-recourse debt associated with the terminated leases) and expects to record a net pre-tax loss of approximately $27 million in the second quarter of 2013, representing the excess of the carrying value of the terminated leases over the net cash proceeds received. PHI estimates that the early termination of the remaining cross-border energy lease investments could be accomplished during 2013. The aggregate financial impact of the liquidation of the cross-border leases is not determinable at this time, but management believes that any gains or losses incurred in the aggregate will not be material; however, there may be individual lease terminations that result in offsetting material gains and losses.

Pension and Postretirement Benefit Plans

Pension benefits are provided under PHI’s non-contributory retirement plan (the PHI Retirement Plan), a defined benefit pension 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 target liability as defined under the Pension Protection Act of 2006.

PHI satisfied the minimum required contribution rules under the Pension Protection Act in 2012 and 2011. In the first quarter of 2013, PHI, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $20 million, $10 million and $30 million, respectively. PHI expects to make an additional discretionary tax-deductible contribution to the PHI Retirement Plan of approximately $60 million during the second quarter of 2013. In the first quarter of 2012, Pepco, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $85 million, $85 million and $30 million, respectively, which brought the PHI Retirement Plan assets to at least the funding target level for 2012 under the Pension Protection Act.

Based on the results of the 2012 actuarial valuation, PHI’s net periodic pension and other postretirement benefit costs were $110 million in 2012 versus $94 million in 2011. The current estimate of benefit cost for 2013 is $99 million. The utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and other postretirement benefit costs. Approximately 30% of 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 $69 million in 2013, as compared to $77 million in 2012.

Cash Flow Activity

PHI’s cash flows for the three months ended March 31, 2013 and 2012 are summarized below:

	Cash Source (Use)
	2013			2012			Change
	(millions of dollars)
Operating Activities	$	(146	)	$	23		$	(169	)
Investing Activities		(296	)		(281	)		(15	)
Financing Activities		542			213			329
Net increase (decrease) in cash and cash equivalents	$	100		$	(45	)	$	145

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Operating Activities

Cash flows from operating activities during the three months ended March 31, 2013 and 2012 are summarized below:

	Cash (Use) Source
	2013			2012			Change
	(millions of dollars)
Net (loss) income from continuing operations	$	(430	)	$	63		$	(493	)
Non-cash adjustments to net income		477			92			385
Pension contributions		(60	)		(200	)		140
Deposit made with taxing authority		(242	)		—			(242	)
Changes in cash collateral related to derivative activities		17			20			(3	)
Changes in other assets and liabilities		95			47			48
Changes in Pepco Energy Services net assets held for sale		(3	)		1			(4	)
Net cash (used by) from operating activities	$	(146	)	$	23		$	(169	)

Net cash from operating activities decreased $169 million for the three months ended March 31, 2013, compared to the same period in 2012. The decrease was primarily due to a decrease in net income of $493 million and a $242 million deposit with the IRS for estimated additional taxes and related interest, partially offset by a $140 million decrease in pension contributions and a $385 million increase in non-cash adjustments to net income primarily associated with the cross-border energy lease investments.

Investing Activities

Cash flows from investing activities during the three months ended March 31, 2013 and 2012 are summarized below:

	Cash Use
	2013			2012			Change
	(millions of dollars)
Investment in property, plant and equipment	$	(296	)	$	(291	)	$	(5	)
Department of Energy (DOE) capital reimbursement awards received		1			7			(6	)
Changes in restricted cash equivalents		2			1			1
Net other investing activities		(3	)		2			(5	)
Net cash used by investing activities	$	(296	)	$	(281	)	$	(15	)

Net cash used by investing activities increased $15 million for the three months ended March 31, 2013, compared to the same period in 2012. The increase was primarily due to a decrease in DOE reimbursement awards received and an increase in investments in property, plant and equipment.

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Financing Activities

Cash flows from financing activities during the three months ended March 31, 2013 and 2012 are summarized below:

	Cash Source
	2013			2012			Change
	(millions of dollars)
Dividends paid on common stock	$	(67	)	$	(61	)	$	(6	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		15			17			(2	)
Issuances of common stock		324			—			324
Issuances of long-term debt		250			—			250
Reacquisitions of long-term debt		(10	)		(9	)		(1	)
Issuances of short-term debt, net		26			253			(227	)
Issuance of term loan		250			—			250
Repayment of term loan		(200	)		—			(200	)
Cost of issuances		(16	)		(3	)		(13	)
Net other financing activities		(30	)		16			(46	)
Net cash from financing activities	$	542		$	213		$	329

Net cash from financing activities increased $329 million for the three months ended March 31, 2013, compared to the same period in 2012. The increase was primarily due to issuances of common stock of $324 million due to the settlement of the equity forward transaction, an issuance of long-term debt of $250 million, and a net $50 million increase in term loans, partially offset by a $227 million decrease in short-term debt issuances.

Changes in Outstanding Long-Term Debt

Cash flows from the issuance and reacquisitions of long-term debt for the three months ended March 31, 2013 and 2012 are summarized below:

	Issuance
	2013		2012
	(millions of dollars)
Pepco
4.15% First mortgage bonds due 2043	$	250	$	—
	$	250	$	—

	Reacquisitions
	2013		2012
	(millions of dollars)
ACE
Securitization bonds due 2012-2013	$	10	$	9
	$	10	$	9

Changes in Short-Term Debt

As of March 31, 2013, PHI had a total of $663 million of commercial paper outstanding as compared to $637 million of commercial paper outstanding as of December 31, 2012.

On March 28, 2013, PHI entered into a $250 million term loan agreement, pursuant to which PHI has borrowed (and may not re-borrow) $250 million. All borrowings under the loan agreement are unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before March 27, 2014. PHI used the net proceeds of the loan under the loan agreement to repay the outstanding $200 million term loan made in 2012, and for general corporate purposes.

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Capital Requirements

Capital Expenditures

Pepco Holdings’ capital expenditures for the three months ended March 31, 2013 were $296 million, of which $125 million was incurred by Pepco, $83 million was incurred by DPL, $74 million was incurred by ACE, $1 million by Pepco Energy Services and $13 million for Corporate and Other. The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. Corporate and Other capital expenditures primarily consisted of hardware and software expenditures that will be allocated to Power Delivery when the assets are placed in service.

In its 2012 Form 10-K, PHI presented its projected capital expenditures for the five-year period 2013 through 2017. There have been no changes in PHI’s projected capital expenditures from those presented in the 2012 Form 10-K. Projected capital expenditures include expenditures for distribution, transmission and gas delivery which primarily relate to facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. These projected capital expenditures also include expenditures for the programs undertaken by each of PHI’s utility subsidiaries to install smart meters, further automate their electric distribution systems and enhance their communications infrastructure, which is referred to as the smart grid.

DOE Capital Reimbursement Awards

In 2009, the DOE announced awards under the American Recovery and Reinvestment Act of 2009 of:

• $105 million and $44 million in Pepco’s Maryland and District of Columbia service territories, respectively, for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure.

• $19 million in ACE’s New Jersey service territory for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure.

During 2010, Pepco, ACE and the DOE signed agreements formalizing the $168 million in awards. Of the $168 million, $130 million is being used for the smart grid and other capital expenditures of Pepco and ACE. The remaining $38 million is being used to offset incremental expenses associated with direct load control and other Pepco and ACE programs. During the three months ended March 31, 2013, Pepco and ACE received award payments of $2 million and less than $1 million, respectively. The cumulative award payments received by Pepco and ACE as of March 31, 2013 were $116 million and $13 million, respectively.

The IRS has announced that, to the extent these grants are expended on capital items, they will not be considered taxable income.

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.

Dividends

On April 25, 2013, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable June 28, 2013 to stockholders of record on June 10, 2013. PHI had approximately $612 million and $1,109 million of retained earnings free of restrictions at March 31, 2013 and December 31, 2012, respectively.

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Energy Contract Net Asset Activity

The following table provides detail on changes in the net liability positions of the Pepco Energy Services segment with respect to electricity commodity contracts for the three months ended March 31, 2013. The balances in the table are pre-tax and the derivative liabilities reflect netting by counterparty before the impact of collateral.

	Energy Commodity Activities (a)
	(millions of dollars)
Total Fair Value of Energy Contract Net Liabilities at December 31, 2012	$	(9	)
Current period unrealized mark-to-market losses		—
Effective portion of changes in fair value – recorded in Accumulated Other Comprehensive Loss		—
Cash flow hedge ineffectiveness – recorded in income		—
Reclassification of mark-to-market losses to realized on settlement of contracts		5
Total Fair Value of Energy Contract Net Liabilities at March 31, 2013	$	(4	)
Detail of Fair Value of Energy Contract Net Liabilities at March 31, 2013 (see above)
Derivative liabilities (current liabilities)	$	(4	)
Derivative liabilities (non-current liabilities)		—
Total Fair Value of Energy Contract Liabilities		(4	)
Total Fair Value of Energy Contract Net Liabilities	$	(4	)

(a) Includes all effective hedging activities from continuing operations recorded at fair value through AOCL or trading activities from continuing operations recorded at fair value in the consolidated statements of income.

The $4 million net liability on electricity contracts at March 31, 2013 was primarily attributable to losses on power swaps held by Pepco Energy Services. The decrease from $9 million at December 31, 2012 is primarily due to the reclassification of mark-to-market losses to realized losses on settled derivatives. PHI expects that future revenues from existing customer sales obligations that are accounted for on an accrual basis will largely offset expected realized net losses on Pepco Energy Services’ electricity contracts.

The fair values of Pepco Energy Services’ electricity commodity derivative contracts in each category presented below reflect forward prices and volatility factors as of March 31, 2013, and the fair values are subject to change as a result of changes in these prices and factors.

	Fair Value of Contracts at March 31, 2013 Maturities
Source of Fair Value	2013			2014		2015		2016 and Beyond		Total Fair Value
	(millions of dollars)
Energy Commodity Activities, net (a)
Actively Quoted (i.e., exchange-traded) prices	$	—		$	—	$	—	$	—	$	—
Prices provided by other external sources (b)		(4	)		—		—		—		(4	)
Modeled		—			—		—		—		—
Total	$	(4	)	$	—	$	—	$	—	$	(4	)

(a) Includes all effective hedging activities recorded at fair value through AOCL, and hedge ineffectiveness and trading activities on the consolidated statements of income.

(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.

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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 March 31, 2013, 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 $126 million. Of this amount, $24 million is 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. The remaining $102 million 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 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 March 31, 2013, Pepco Energy Services provided net cash collateral in the amount of $5 million in connection with these activities.

Regulatory and Other Matters

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland 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.

In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015. The order requires Pepco, DPL and BGE (collectively, the Contract EDCs), to negotiate and enter into a contract with the winning bidder of a competitive bidding process in amounts proportional to their relative SOS loads. Under the contract, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015. The order acknowledged the Contract EDCs’ concerns about the requirements of the contract and directed them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specified that the Contract EDCs will recover the associated costs through surcharges on their respective SOS customers.

In April 2012, a group of generating companies operating in the PJM region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, the Contract EDCs and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These appeals were consolidated in the Circuit Court for Baltimore City and stayed pending the issuance of a final order from the MPSC approving the form of contract.

On April 16, 2013, the MPSC issued an order approving a final form of the contract and directing the Contract EDCs to enter into the contract, in amounts proportional to their relative SOS loads, with the winning bidder within 20 days of the order (i.e., by May 6, 2013). The MPSC stated that the order, which approves timely and complete recovery by the Contract EDCs of the costs associated with the contract,

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constitutes a binding commitment that shall not be subject to future modification or rescission by the MPSC. Despite this commitment from the MPSC, Pepco and DPL believe that the attempt by the MPSC to bind a future commission in this manner may be subject to legal challenge, which challenge, if successful, could impair the right of Pepco and DPL to recover their costs in the future. In addition, the MPSC excluded from the contract a provision that Pepco and DPL believe is important to mitigate their financial risk because the provision, had it been included, would have required Pepco and DPL to make payments to the winning bidder under the contract only to the extent they were able to recover those costs (for example, Pepco and DPL believe the excluded provision would have protected them in the event a significant number of their SOS customers elect to buy their energy from alternative energy suppliers). In light of the issuance of the MPSC’s final order, the previously filed appeals of the MPSC’s actions in this case before the circuit court will now proceed. Pepco and DPL anticipate that, in accordance with the terms of the MPSC’s order, they will enter into the contract within the 20-day period; however, under its own terms, the contract will not become effective, if at all, until all legal proceedings related to this contract or the actions of the MPSC in the related proceeding have been resolved.

Until a final non-appealable court decision is rendered in connection with all such legal proceedings, PHI cannot predict (i) the extent of the negative effect that the contract for new generation may have on PHI’s, Pepco’s and DPL’s balance sheets, as well as their respective credit metrics, as calculated by independent rating agencies that evaluate and rate PHI, Pepco and DPL and each of their debt issuances, (ii) the effect on Pepco’s and DPL’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contract on the financial condition, results of operations and cash flows of each of PHI, Pepco and DPL.

For a discussion of other regulatory matters, see Note (7), “Regulatory Matters,” to the consolidated financial statements of PHI.

Legal Proceedings

For a discussion of legal proceedings, see Note (15), “Commitments and Contingencies,” to the consolidated financial statements of PHI.

Critical Accounting Policies

For a discussion of Pepco Holdings’ critical accounting policies, please refer to Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Pepco Holdings’ 2012 Form 10-K. There have been no material changes to PHI’s critical accounting policies as disclosed in the 2012 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.

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

Potomac Electric Power Company

Pepco meets the conditions set forth in General Instruction H(1)(a) and (b) to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction H(2) to Form 10-Q.

General Overview

Pepco is engaged in the transmission and distribution of electricity in the District of Columbia and significant portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply. Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.2 million. As of March 31, 2013, approximately 58% of delivered electricity sales were to Maryland customers and approximately 42% were to District of Columbia customers.

Pepco’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco in Maryland and in the District of Columbia, revenue is not affected by unseasonably warmer or colder weather because a BSA for retail customers was implemented that provides for a fixed distribution charge per customer rather than a charge based on energy usage. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers 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. Changes in customer usage (due to weather conditions, energy prices, energy savings programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.

In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland and District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer.

Pepco is a wholly owned subsidiary of PHI. Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between each of PHI, PHI Service Company (a subsidiary service company of PHI, which provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services to PHI and its operating subsidiaries) and Pepco, as well as certain activities of Pepco, are subject to FERC’s regulatory oversight under PUHCA 2005.

Reliability Enhancement

Since 2010, Pepco has implemented comprehensive reliability enhancement plans in its service territory. These reliability enhancement plans include various initiatives to improve electrical system reliability, such as:

• 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 systems;

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• the rejuvenation and replacement of underground residential cables;

• selective undergrounding of portions of existing above-ground primary feeder lines, where appropriate to improve reliability;

• improvements to substation supply lines; and

• enhanced vegetation management.

Smart Grid

Pepco is building a “smart grid” which is designed to meet the challenges of rising energy costs, respond to concerns about the environment, improve reliability, provide timely and accurate customer information and address government energy reduction goals. For a discussion of the smart grid, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Power Delivery Initiatives and Activities – Smart Grid.”

Mitigation of Regulatory Lag

An important factor in the ability of Pepco to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in its rate structure in order to address the shortfall in revenues due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Pepco is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth.

In an effort to minimize the effects of regulatory lag, Pepco’s District of Columbia and Maryland base rate case filings in 2011 each included a request for approval from the applicable state regulatory commissions of (i) a RIM to recover reliability-related capital expenditures incurred between base rate cases and (ii) the use by the applicable utility of fully forecasted test years in future base rate cases. In the Pepco base rate case order issued by the MPSC in 2012, the MPSC did not approve Pepco’s requests to implement the RIM and did not endorse the use by Pepco of fully forecasted test years in future rate cases. However, the MPSC did permit an adjustment to the rate base of Pepco to reflect the actual cost of reliability plant additions outside the test year. In the District of Columbia, the DCPSC denied Pepco’s request for approval of a RIM in 2012, and reserved final judgment on the appropriateness of the use by Pepco of a fully forecasted test year in future rate cases.

Pepco will continue to seek cost recovery from applicable public service commissions to reduce the effects of regulatory lag. There can be no assurance that any attempts by Pepco to mitigate regulatory lag will be approved, or that even if approved, the cost recovery mechanisms will fully mitigate the effects of regulatory lag. Until such time as any cost recovery mechanisms are approved, Pepco plans to file rate cases at least annually in an effort to align more closely the revenue and cash flow levels with other operation and maintenance spending and capital investments. Pepco filed electric distribution base rate cases in November 2012 in Maryland and in March 2013 in the District of Columbia. In Maryland, Pepco included a proposed three-year Grid Resiliency Charge rider intended to reduce regulatory lag. This rider provides for recovery of costs associated with Pepco’s respective plans to accelerate investments in electric distribution infrastructure in a condensed timeframe. See Note (6), “Regulatory Matters – Rate Proceedings,” to the financial statements of Pepco for more information about these base rate cases.

MAPP Project

On August 24, 2012, the board of PJM terminated the MAPP project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. As of December 31, 2012, Pepco’s total costs related to the MAPP project were $64 million. In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the

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recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, PHI submitted a filing to FERC seeking recovery of $50 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

Various protests were submitted in response to PHI’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of Pepco, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by Pepco to be $1 million) of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. Pepco believes that the FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request on behalf of Pepco of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that PHI is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. Pepco cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, Pepco had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories, for use on other projects, and reclassified the remaining $50 million of capital expenditures to a regulatory asset. During the first quarter of 2013, Pepco further transferred an additional $2 million of materials to inventories, for use on other projects, and expensed $1 million of abandoned costs as a result of FERC’s disallowance noted above, resulting in a regulatory asset of $47 million as of March 31, 2013. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. Pepco intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with FERC against Pepco, DPL and ACE, as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that Pepco provides. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for Pepco is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. Pepco believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, Pepco filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

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Results of Operations

The following results of operations discussion compares the three months ended March 31, 2013 to the three months ended March 31, 2012. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2013		2012		Change
Regulated T&D Electric Revenue	$	269	$	264	$	5
Default Electricity Supply Revenue		199		193		6
Other Electric Revenue		9		8		1
Total Operating Revenue	$	477	$	465	$	12

The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated 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.

The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes 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 include mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

Regulated T&D Electric

	2013		2012		Change
Regulated T&D Electric Revenue
Residential	$	79	$	77	$	2
Commercial and industrial		149		148		1
Transmission and other		41		39		2
Total Regulated T&D Electric Revenue	$	269	$	264	$	5

	2013		2012		Change
Regulated T&D Electric Sales (GWh)
Residential		2,149		1,958		191
Commercial and industrial		4,161		4,209		(48	)
Transmission and other		45		44		1
Total Regulated T&D Electric Sales		6,355		6,211		144

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	2013		2012		Change
Regulated T&D Electric Customers (in thousands)
Residential		722		717		5
Commercial and industrial		74		74		—
Transmission and other		—		—		—
Total Regulated T&D Electric Customers		796		791		5

Regulated T&D Electric Revenue increased by $5 million primarily due to:

• An increase of $3 million due to a distribution rate increase in the District of Columbia effective October 2012, and in Maryland effective July 2012.

• An increase of $2 million in transmission revenue primarily attributable to higher capacity revenue as a result of expanding Maryland demand-side management programs (which is substantially offset by a corresponding increase in Depreciation and Amortization).

Default Electricity Supply

	2013		2012		Change
Default Electricity Supply Revenue
Residential	$	143	$	138	$	5
Commercial and industrial		52		53		(1	)
Other		4		2		2
Total Default Electricity Supply Revenue	$	199	$	193	$	6

	2013		2012		Change
Default Electricity Supply Sales (GWh)
Residential		1,645		1,581		64
Commercial and industrial		679		650		29
Other		9		2		7
Total Default Electricity Supply Sales		2,333		2,233		100

	2013		2012		Change
Default Electricity Supply Customers (in thousands)
Residential		565		595		(30	)
Commercial and industrial		44		45		(1	)
Other		—		—		—
Total Default Electricity Supply Customers		609		640		(31	)

Default Electricity Supply Revenue increased by $6 million primarily due to:

• An increase of $17 million due to higher sales as a result of colder weather during the 2013 winter months, as compared to 2012.

• An increase of $2 million due to higher revenue from transmission enhancement credits.

The aggregate amount of these increases was partially offset by:

• A decrease of $5 million as a result of lower Default Electricity Supply rates.

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• A decrease of $4 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

• A decrease of $4 million due to lower non-weather related residential and commercial customer usage.

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

	2013			2012
Sales to District of Columbia customers		28	%		26	%
Sales to Maryland customers		43	%		43	%

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 increased by $7 million to $192 million in 2013 from $185 million in 2012 primarily due to:

• An increase of $15 million due to higher electricity sales primarily as a result of colder weather during the 2013 winter months, as compared to 2012.

• An increase of $2 million in deferred electricity expense primarily due to lower Default Electricity Supply rates, which resulted in a higher rate of recovery of Default Electricity Supply costs.

The aggregate amount of these increases was partially offset by:

• A decrease of $7 million primarily due to customer migration to competitive suppliers.

• A decrease of $4 million due to lower average electricity costs under Default Electricity Supply contracts.

Other Operation and Maintenance

Other Operation and Maintenance expense decreased by $1 million to $102 million in 2013 from $103 million in 2012 primarily due to:

• A decrease of $3 million due to the deferral of certain customer service costs incurred in 2011 and 2012 that had been previously charged to Other Operation and Maintenance expense. The deferral was recorded in accordance with an MPSC order issued in January 2013, authorizing the establishment of a regulatory asset for the recovery of these costs.

• A decrease of $2 million in other customer service costs.

• A decrease of $1 million associated with lower tree trimming and maintenance costs.

The aggregate amount of these decreases was partially offset by:

• An increase of $3 million in incremental preparation and restoration costs associated with a winter storm in March 2013.

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• An increase of $1 million in employee-related costs, primarily benefit expenses.

• An increase of $1 million associated with the write-off of disallowed abandoned MAPP costs.

Other Taxes

Other Taxes decreased by $1 million to $89 million in 2013 from $90 million in 2012. The decrease was primarily due to decreases in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding decrease in Regulated T&D Electric Revenue).

Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $1 million to a net expense of $22 million in 2013 from a net expense of $21 million in 2012. The increase was primarily due to an increase of $1 million in interest expense primarily associated with higher long-term debt.

Income Tax Expense

Pepco’s income tax expense increased by $7 million to an expense of $2 million in 2013 from a benefit of $5 million in 2012. Pepco’s effective tax rates for the three months ended March 31, 2013 and 2012 were 8.0% and (26.3)%, respectively. The increase in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which Pepco is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that it can no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded a charge of $377 million (after-tax) in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in Pepco recording a $5 million interest benefit in the first quarter of 2013.

In the first quarter of 2012, Pepco recorded tax benefits of $10 million for changes in estimates and interest related to uncertain and effectively settled tax positions primarily due to the effective settlement with the Internal Revenue Service with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position.

Capital Requirements

Capital Expenditures

Pepco’s capital expenditures for the three months ended March 31, 2013 were $125 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 Power Delivery and are allocated to Pepco when the assets are placed in service.

In its 2012 Form 10-K, Pepco presented its projected capital expenditures for the five-year period 2013 through 2017. There have been no changes in Pepco’s projected capital expenditures from those presented

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in the 2012 Form 10-K. Projected capital expenditures include expenditures for distribution and transmission, which primarily relate to facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. These projected capital expenditures also include expenditures for the programs undertaken by Pepco to install smart meters, further automate electric distribution systems and enhance Pepco’s communications infrastructure, which is referred to as the smart grid.

DOE Capital Reimbursement Awards

During 2009, the DOE announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure. Pepco was awarded $149 million, with $105 million to be used in the Maryland service territory and $44 million to be used in the District of Columbia service territory.

During 2010, Pepco and the DOE signed agreements formalizing Pepco’s $149 million share of the $168 million award. Of the $149 million, $118 million is being used for the smart grid and other capital expenditures of Pepco. The remaining $31 million is being used to offset incremental expenses associated with direct load control and other programs. For the three months ended March 31, 2013, Pepco received award payments of $2 million. Cumulative award payments received by Pepco as of March 31, 2013 were $116 million.

The IRS has announced that, to the extent these grants are expended on capital items, they will not be considered taxable income.

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

Delmarva Power & Light Company

DPL meets the conditions set forth in General Instruction H(1)(a) and (b) to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction H(2) to Form 10-Q.

General Overview

DPL is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland. DPL also provides Default Electricity Supply. DPL’s electricity distribution service territory covers approximately 5,000 square miles and has a population of approximately 1.4 million. As of March 31, 2013, approximately 64% of delivered electricity sales were to Delaware customers and approximately 36% 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 who 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.

DPL’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of DPL in Maryland, revenues are not affected by unseasonably warmer or colder weather because a BSA for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A comparable revenue decoupling mechanism for DPL electricity and natural gas customers in Delaware is under consideration by the DPSC. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.

In accounting for the BSA in Maryland, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer.

DPL is a wholly owned subsidiary of Conectiv, LLC (Conectiv) which is wholly owned by PHI. Because each of PHI and Conectiv is a public utility holding company subject to PUHCA 2005, the relationship between each of PHI, Conectiv, PHI Service Company and DPL, as well as certain activities of DPL, are subject to FERC’s regulatory oversight under PUHCA 2005.

Smart Grid

DPL is building a smart grid which is designed to meet the challenges of rising energy costs, respond to concerns about the environment, improve reliability, provide timely and accurate customer information and address government energy reduction goals. For a discussion of the smart grid, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Power Delivery Initiatives and Activities – Smart Grid.”

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Mitigation of Regulatory Lag

An important factor in the ability of DPL to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in its rate structure in order to address the shortfall in revenues due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” DPL is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth.

In an effort to minimize the effects of regulatory lag, DPL’s Delaware and Maryland base rate case filings in 2011 each included a request for approval from the applicable state regulatory commissions of (i) a RIM to recover reliability-related capital expenditures incurred between base rate cases and (ii) the use by the applicable utility of fully forecasted test years in future base rate cases. In the DPL base rate case orders issued by the MPSC in 2012, the MPSC did not approve DPL’s requests to implement the RIM and did not endorse the use by DPL of fully forecasted test years in future rate cases. However, the MPSC did permit an adjustment to the rate base of DPL to reflect the actual cost of reliability plant additions outside the test year. In Delaware, a settlement agreement approved by the DPSC in DPL’s electric distribution base rate case did not include approval of a RIM or the use of fully forecasted test years in future DPL rate cases, but it did provide that the parties will meet and discuss alternate regulatory methodologies for the mitigation of regulatory lag.

DPL will continue to seek cost recovery from applicable public service commissions to reduce the effects of regulatory lag. There can be no assurance that any attempts by DPL to mitigate regulatory lag will be approved, or that even if approved, the cost recovery mechanisms will fully mitigate the effects of regulatory lag. Until such time as any cost recovery mechanisms are approved, DPL plans to file rate cases at least annually in an effort to align more closely the revenue and cash flow levels with other operation and maintenance spending and capital investments. DPL filed electric distribution base rate cases in both Delaware and Maryland in March 2013, and filed a natural gas distribution case in December 2012. In DPL’s electric distribution base rate case filed in Maryland, DPL included a proposed three-year Grid Resiliency Charge rider intended to reduce regulatory lag. This rider provides for recovery of costs associated with DPL’s respective plans to accelerate investments in electric distribution infrastructure in a condensed timeframe. See Note (7), “Regulatory Matters – Rate Proceedings,” to the financial statements of DPL for more information about these base rate cases.

MAPP Project

On August 24, 2012, the board of PJM terminated the MAPP project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. As of December 31, 2012, DPL’s total costs related to the MAPP project were $38 million. In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, PHI submitted a filing to FERC seeking recovery of $38 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

Various protests were submitted in response to PHI’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of DPL, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for

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those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by DPL to be $1 million) of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. DPL believes that the FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request on behalf of DPL of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that DPL is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. DPL cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, DPL had reclassified all $38 million of capital expenditures with respect to the MAPP project to a regulatory asset. During the first quarter of 2013, DPL expensed $1 million of prudently incurred abandoned costs as a result of FERC’s disallowance noted above, resulting in a regulatory asset of $37 million as of March 31, 2013. The regulatory asset includes the costs of land, land rights, engineering and design, environmental services, and project management and administration. DPL intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land and land rights.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with FERC against DPL, Pepco and ACE, as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that DPL provides. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for DPL is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. DPL believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, DPL filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

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DPL

Results of Operations

The following results of operations discussion compares the three months ended March 31, 2013 to the three months ended March 31, 2012. All amounts in the tables (except sales and customers) are in millions of dollars.

Electric Operating Revenue

	2013		2012		Change
Regulated T&D Electric Revenue	$	127	$	106	$	21
Default Electricity Supply Revenue		154		149		5
Other Electric Revenue		4		4		—
Total Electric Operating Revenue	$	285	$	259	$	26

The table above shows the amount of Electric Operating Revenue earned that is subject to price regulation (Regulated 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 territories 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.

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

Regulated T&D Electric

	2013		2012		Change
Regulated T&D Electric Revenue
Residential	$	64	$	52	$	12
Commercial and industrial		34		27		7
Transmission and other		29		27		2
Total Regulated T&D Electric Revenue	$	127	$	106	$	21

	2013		2012		Change
Regulated T&D Electric Sales (GWh)
Residential		1,530		1,293		237
Commercial and industrial		1,788		1,740		48
Transmission and other		12		12		—
Total Regulated T&D Electric Sales		3,330		3,045		285

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DPL

	2013		2012		Change
Regulated T&D Electric Customers (in thousands)
Residential		443		442		1
Commercial and industrial		59		59		—
Transmission and other		1		1		—
Total Regulated T&D Electric Customers		503		502		1

Regulated T&D Electric Revenue increased by $21 million primarily due to:

• An increase of $11 million primarily due to a Renewable Portfolio Surcharge in Delaware effective June 2012 (which is substantially offset by corresponding increases in Purchased Energy and Depreciation and Amortization).

• An increase of $7 million due to distribution rate increases in Maryland and in Delaware, each effective July 2012.

• An increase of $3 million due to higher sales as a result of colder weather during the 2013 winter months, as compared to 2012.

• An increase of $1 million due to an EmPower Maryland rate increase in February 2012 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

The aggregate amount of these increases was partially offset by a decrease of $2 million in transmission revenue primarily attributable to a less favorable FERC formula rate true-up.

Default Electricity Supply

	2013		2012		Change
Default Electricity Supply Revenue
Residential	$	125	$	115	$	10
Commercial and industrial		27		31		(4	)
Other		2		3		(1	)
Total Default Electricity Supply Revenue	$	154	$	149	$	5

	2013		2012		Change
Default Electricity Supply Sales (GWh)
Residential		1,352		1,197		155
Commercial and industrial		339		451		(112	)
Other		7		7		—
Total Default Electricity Supply Sales		1,698		1,655		43

	2013		2012		Change
Default Electricity Supply Customers (in thousands)
Residential		401		415		(14	)
Commercial and industrial		39		42		(3	)
Other		—		—		—
Total Default Electricity Supply Customers		440		457		(17	)

158

DPL

Default Electricity Supply Revenue increased by $5 million primarily due to:

• An increase of $12 million due to higher sales as a result of colder weather during the 2013 winter months, as compared to 2012.

• An increase of $8 million due to higher non-weather related average residential customer usage.

The aggregate amount of these increases was partially offset by:

• A decrease of $11 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

• A decrease of $4 million as a result of lower Default Electricity Supply rates.

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

	2013			2012
Sales to Delaware customers		48	%		52	%
Sales to Maryland customers		56	%		59	%

Natural Gas Operating Revenue

	2013		2012		Change
Regulated Gas Revenue	$	73	$	65	$	8
Other Gas Revenue		12		9		3
Total Natural Gas Operating Revenue	$	85	$	74	$	11

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.

Regulated Gas

	2013		2012		Change
Regulated Gas Revenue
Residential	$	48	$	43	$	5
Commercial and industrial		22		19		3
Transportation and other		3		3		—
Total Regulated Gas Revenue	$	73	$	65	$	8

	2013		2012		Change
Regulated Gas Sales (million cubic feet)
Residential		4,072		3,045		1,027
Commercial and industrial		2,061		1,553		508
Transportation and other		2,432		2,129		303
Total Regulated Gas Sales		8,565		6,727		1,838

159

DPL

	2013		2012		Change
Regulated Gas Customers (in thousands)
Residential		115		114		1
Commercial and industrial		10		10		—
Transportation and other		—		—		—
Total Regulated Gas Customers		125		124		1

Regulated Gas Revenue increased by $8 million primarily due to:

• An increase of $17 million due to higher sales primarily as a result of colder weather during the winter months of 2013, as compared to 2012.

• An increase of $5 million due to higher non-weather related average commercial and residential customer usage.

The aggregate amount of these increases was partially offset by a decrease of $13 million due to a GCR decrease effective November 2012.

Other Gas Revenue

Other Gas Revenue increased by $3 million primarily due to higher average prices and higher volumes for 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 increased by $16 million to $159 million in 2013 from $143 million in 2012 primarily due to:

• An increase of $10 million due to higher electricity sales primarily as a result of colder weather during the 2013 winter months, as compared to 2012.

• An increase of $9 million in deferred electricity expense primarily due to a Renewable Portfolio Surcharge in Delaware effective June 2012 (which is substantially offset by corresponding increases in Regulated T&D Electric Revenue).

• An increase of $2 million due to higher average electricity costs under Default Electricity Supply contracts.

The aggregate amount of these increases was partially offset by a decrease of $7 million primarily due to customer migration to competitive suppliers.

160

DPL

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 increased by $5 million to $54 million in 2013 from $49 million in 2012 primarily due to:

• An increase of $4 million in the cost of gas purchases for on-system sales as a result of higher average gas prices and higher volumes purchased.

• An increase of $4 million in the cost of gas purchases for off-system sales as a result of higher average gas prices and higher volumes purchased.

• An increase of $1 million in deferred gas expense as a result of a higher rate of recovery of natural gas supply costs.

The aggregate amount of these increases was partially offset by:

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

Other Operation and Maintenance

Other Operation and Maintenance expense increased by $4 million to $69 million in 2013 from $65 million in 2012 primarily due to:

• An increase of $2 million associated with the write-offs of disallowed abandoned MAPP and transmission project costs.

• An increase of $1 million in incremental preparation and restoration costs associated with a winter storm in March 2013.

• An increase of $1 million in employee-related costs, primarily benefit expenses.

Depreciation and Amortization

Depreciation and Amortization expense increased by $1 million to $25 million in 2013 from $24 million in 2012 primarily due to an increase of $1 million in amortization of regulatory assets primarily due to an EmPower Maryland surcharge rate increase effective February 2012 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

Other Income (Expense)

Other Expenses (which are net of Other Income) increased by $3 million to a net expense of $11 million in 2013 from a net expense of $8 million in 2012. The increase was primarily due to an increase of $3 million in long-term debt interest expense due to $250 million of First Mortgage Bonds issued June 2012.

Income Tax Expense

DPL’s income tax expense increased by $2 million to $16 million in 2013 from $14 million in 2012. DPL’s effective tax rates for the three months ended March 31, 2013 and 2012 were 38.1% and 40.0%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which DPL is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that it can no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded a charge of $377 million (after-tax) in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in DPL recording a $1 million interest benefit in the first quarter of 2013.

161

DPL

Capital Requirements

Capital Expenditures

DPL’s capital expenditures for the three months ended March 31, 2013 were $83 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 Power Delivery and are allocated to DPL when the assets are placed in service.

In its 2012 Form 10-K, DPL presented the projected capital expenditures for the five-year period 2013 through 2017. There have been no changes in DPL’s projected capital expenditures from those presented in the 2012 Form 10-K. Projected capital expenditures include expenditures for distribution, transmission, and gas delivery which primarily relate to facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. These projected capital expenditures also include expenditures for the programs undertaken by DPL to install smart meters, further automate electric distribution systems and enhance DPL’s communications infrastructure, which is referred to as the smart grid.

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ACE

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

Atlantic City Electric Company

ACE meets the conditions set forth in General Instruction H(1)(a) and (b) to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction H(2) to Form 10-Q.

General Overview

ACE is engaged in the transmission and distribution of electricity in southern New Jersey. ACE also provides Default Electricity Supply. Default Electricity Supply is known as BGS in New Jersey. ACE’s service territory covers approximately 2,700 square miles and has a population of approximately 1.1 million.

ACE is a wholly owned subsidiary of Conectiv, which is wholly owned by PHI. Because each of PHI and Conectiv is a public utility holding company subject to PUHCA 2005, the relationship between each of PHI, Conectiv, PHI Service Company and ACE, as well as certain activities of ACE, are subject to FERC’s regulatory oversight under PUHCA 2005.

Smart Grid

ACE is building a smart grid which is designed to meet the challenges of rising energy costs, respond to concerns about the environment, improve reliability, provide timely and accurate customer information and address government energy reduction goals. The installation of smart meters currently has been deferred by the NJBPU. For a discussion of the smart grid, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Power Delivery Initiatives and Activities – Smart Grid.”

Mitigation of Regulatory Lag

An important factor in the ability of ACE to earn its authorized rate of return is the willingness of the NJBPU to adequately recognize forward-looking costs in its rate structure in order to address the shortfall in revenues due to regulatory lag. ACE is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth. The NJBPU has approved certain cost recovery mechanisms in connection with ACE’s Infrastructure Investment Program, which ACE had proposed in 2011 to extend and expand; however, in connection with the settlement in October 2012 of its electric distribution base rate case, ACE withdrew this proposal without prejudice. There can be no assurance that any future attempts by ACE to mitigate regulatory lag will be approved, or that even if approved, any proposed cost recovery mechanisms will fully mitigate the effects of regulatory lag. Until such time as any cost recovery mechanisms are approved, ACE plans to file rate cases at least annually in an effort to align more closely its revenue and cash flow levels with other operation and maintenance spending and capital investments. ACE filed an electric distribution base rate case on December 11, 2012.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with FERC against Pepco, DPL and ACE, as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s utilities provide. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for ACE is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base

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ACE

ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. ACE believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, ACE filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

Results of Operations

The following results of operations discussion compares the three months ended March 31, 2013 to the three months ended March 31, 2012. All amounts in the tables (except sales and customers) are in millions of dollars.

Operating Revenue

	2013		2012		Change
Regulated T&D Electric Revenue	$	95	$	82	$	13
Default Electricity Supply Revenue		178		170		8
Other Electric Revenue		4		4		—
Total Operating Revenue	$	277	$	256	$	21

The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated 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 at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

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 ACE Funding, to fund the principal and interest payments on Transition Bonds issued by ACE Funding, and revenue in the form of 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 include mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

Regulated T&D Electric

	2013		2012		Change
Regulated T&D Electric Revenue
Residential	$	41	$	33	$	8
Commercial and industrial		33		26		7
Transmission and other		21		23		(2	)
Total Regulated T&D Electric Revenue	$	95	$	82	$	13

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ACE

	2013		2012		Change
Regulated T&D Electric Sales (GWh)
Residential		1,036		944		92
Commercial and industrial		1,171		1,132		39
Transmission and other		13		12		1
Total Regulated T&D Electric Sales		2,220		2,088		132

	2013		2012		Change
Regulated T&D Electric Customers (in thousands)
Residential		478		481		(3	)
Commercial and industrial		65		65		—
Transmission and other		1		1		—
Total Regulated T&D Electric Customers		544		547		(3	)

Regulated T&D Electric Revenue increased by $13 million primarily due to:

• An increase of $6 million due to distribution and customer charge rate increases, each effective November 2012.

• An increase of $5 million due to a rate increase in the New Jersey Societal Benefit Charge effective July 2012 (which is offset in Deferred Electric Service Costs).

• An increase of $2 million due to higher sales as a result of colder weather during the 2013 winter months, as compared to 2012.

• An increase of $2 million due to higher non-weather related average residential, commercial and industrial customer usage.

The aggregate amount of these increases was partially offset by a decrease of $2 million in transmission revenue primarily attributable to a peak load decrease effective January 2013.

Default Electricity Supply

	2013		2012		Change
Default Electricity Supply Revenue
Residential	$	107	$	105	$	2
Commercial and industrial		45		46		(1	)
Other		26		19		7
Total Default Electricity Supply Revenue	$	178	$	170	$	8

Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated NUGs and (ii) revenue from transmission enhancement credits.

	2013		2012		Change
Default Electricity Supply Sales (GWh)
Residential		821		800		21
Commercial and industrial		237		292		(55	)
Other		4		6		(2	)
Total Default Electricity Supply Sales		1,062		1,098		(36	)

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ACE

	2013		2012		Change
Default Electricity Supply Customers (in thousands)
Residential		388		416		(28	)
Commercial and industrial		44		48		(4	)
Other		—		—		—
Total Default Electricity Supply Customers		432		464		(32	)

Default Electricity Supply Revenue increased by $8 million primarily due to:

• An increase of $7 million in wholesale energy and capacity resale revenues primarily due to higher market prices for the resale of electricity and capacity purchased from NUGs.

• An increase of $7 million due to higher sales as a result of colder weather during the 2013 winter months, as compared to 2012.

• An increase of $5 million due to higher non-weather related average residential customer usage.

• An increase of $4 million as a result of higher Default Electricity Supply rates, primarily due to a Nonutility Generation Charge rate increase that became effective in July 2012.

The aggregate amount of these increases was partially offset by a decrease of $15 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

Total Default Electricity Supply Revenue for the three months ended March 31, 2013 includes an increase of $6 million in unbilled revenue attributable to ACE’s BGS ($4 million increase in net income), primarily due to higher non-weather related average customer usage and higher weather related sales during the unbilled revenue period at March 31, 2013 as compared to the corresponding period in 2012. Under the BGS terms approved by the NJBPU, ACE’s BGS unbilled revenue is not included in the deferral calculation until it is billed to customers, and therefore has an impact on the results of operations in the period during which it is accrued.

For the three months ended March 31, 2013 and 2012, the percentages of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 48% and 53%, 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 $9 million to $157 million in 2013 from $166 million in 2012 primarily due to:

• A decrease of $10 million primarily due to customer migration to competitive suppliers.

• A decrease of $3 million due to lower average electricity costs under Default Electricity Supply contracts.

The aggregate amount of these decreases was partially offset by an increase of $5 million due to higher electricity sales primarily as a result of colder weather during the 2013 winter months, as compared to 2012.

166

ACE

Other Operation and Maintenance

Other Operation and Maintenance expense increased by $5 million to $61 million in 2013 from $56 million in 2012 primarily due to:

• An increase of $2 million associated with higher tree trimming costs.

• An increase of $1 million in incremental preparation and restoration costs associated with a winter storm in March 2013.

• An increase of $1 million in employee-related costs, primarily benefit expenses.

Depreciation and Amortization

Depreciation and Amortization expense increased by $3 million to $31 million in 2013 from $28 million in 2012 primarily due to:

• An increase of $2 million in amortization of stranded costs primarily as the result of higher revenue as the result of higher sales for the ACE Transition Bond Charge and Market Transition charge tax (partially offset in Default Electric Supply Revenue).

• An increase of $1 million due to utility plant additions.

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 $16 million to an expense of $1 million in 2013 as compared to an expense reduction of $15 million in 2012, primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply and New Jersey Societal Benefit Programs revenue rates and lower electricity supply costs.

Income Tax Expense

ACE’s income tax benefit increased by $2 million to $3 million in 2013 from $1 million in 2012. ACE’s consolidated effective tax rates for the three months ended March 31, 2013 and 2012 were (50.3)% and (100)%, respectively. The change in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions. In the first quarter of 2013, ACE recorded an interest benefit of $6 million as discussed further below. In the first quarter of 2012, ACE recorded an interest benefit as a result of the effective settlement with the Internal Revenue Service with respect to the methodology used historically to calculate deductible mixed service costs.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which ACE is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that it can no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded a charge of $377 million (after-tax) in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in ACE recording a $6 million interest benefit in the first quarter of 2013.

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ACE

Capital Requirements

Capital Expenditures

ACE’s capital expenditures for the three months ended March 31, 2013 were $74 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 Power Delivery and are allocated to ACE when the assets are placed in service.

In its 2012 Form 10-K, ACE presented the projected capital expenditures for the five-year period 2013 through 2017. There have been no changes in ACE’s projected capital expenditures from those presented in the 2012 Form 10-K. Projected capital expenditures include expenditures for distribution and transmission, which primarily relate to facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. These projected capital expenditures also include expenditures for the programs undertaken by ACE to install smart meters (for which approval by the NJBPU has been deferred), further automate electric distribution systems and enhance ACE’s communications infrastructure, which is referred to as the smart grid.

DOE Capital Reimbursement Awards

During 2009, the DOE announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure, of which $19 million was for ACE’s service territory.

During 2010, ACE and the DOE signed agreements formalizing ACE’s $19 million share of the $168 million award. Of the $19 million, $12 million is being used for the smart grid and other capital expenditures of ACE. The remaining $7 million is being used to offset incremental expenses associated with direct load control and other programs. For the three months ended March 31, 2013, ACE received award payments of less than $1 million. Cumulative award payments received by ACE as of March 31, 2013 were $13 million.

The IRS has announced that, to the extent these grants are expended on capital items, they will not be considered taxable income.

168

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 (CRMC), 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 CRMC monitors interest rate fluctuation, commodity price fluctuation, 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 herein, refer to Note (2), “Significant Accounting Policies – Accounting For Derivatives,” Note (14), “Derivative Instruments and Hedging Activities,” and Note (19), “Discontinued Operations,” of the consolidated financial statements of PHI included in its 2012 Form 10-K, Part II, Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” in PHI’s 2012 Form 10-K, and Note (13), “Derivative Instruments and Hedging Activities,” and Note (17), “Discontinued Operations,” 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 FASB guidance on derivatives and hedging, (ASC 815). Pepco Energy Services also manages commodity risk with contracts that are not classified as derivatives.

PHI’s risk management policies place oversight at the senior management level through the CRMC, 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.

169

The table below provides the VaR associated with energy contracts of the Pepco Energy Services segment for the three months ended March 31, 2013 in millions of dollars:

	VaR (a)
95% confidence level, one-day holding period, one-tailed
Period end	$	—
Average for the period	$	—
High	$	1
Low	$	—

(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 futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical 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 competitive wholesale energy contracts, net of collateral, to wholesale counterparties as of March 31, 2013, 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)	$	2	$	—	$	2		1	$	2
Non-Investment Grade		—		—		—		—		—
No External Ratings		—		—		—		—		—
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 energy contract net assets for open/unrealized transactions, the net receivable/payable for realized transactions and net open positions for contracts not marked to market. Amounts due from counterparties are offset by liabilities payable to those counterparties to the extent that legally enforceable netting arrangements are in place. Thus, this column presents the net credit exposure to counterparties after reflecting all allowable netting, but before considering collateral held.

(c) Credit collateral - the face amount of cash deposits, letters of credit and performance bonds received from counterparties, not adjusted for probability of default, and, if applicable, property interests (including oil and gas reserves).

(d) Using a percentage of the total exposure.

For information regarding “Interest Rate Risk,” please refer to Part II, Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in Pepco Holdings’ 2012 Form 10-K.

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.

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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 such 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 March 31, 2013, 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 March 31, 2013, 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 (11), “Commitments and Contingencies,” to the financial statements of Pepco included herein, which description is incorporated by reference herein.

DPL

Other than ordinary routine litigation incidental to its business, DPL is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (13), “Commitments and Contingencies,” to the financial statements of DPL included herein, which description is incorporated by reference herein.

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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 (12), “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 2012 Form 10-K. There have been no material changes to any Reporting Company’s risk factors as disclosed in the 2012 Form 10-K, except as set forth below.

Facilities and related systems may not operate as planned or may require significant capital or operation and maintenance expenditures, which could decrease revenues or increase expenses.

Operation of the Pepco, DPL and ACE transmission and distribution facilities and related systems involves many risks, including: the breakdown or failure of equipment; accidents; labor disputes; theft of copper wire or pipe; scams; failure of computer systems, software or hardware; and performance below expected levels. Older facilities, systems 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. Thefts of copper wire or pipe, which seek to capitalize on the current high market price of copper, increase the likelihood of poor system voltage control, electricity and streetlight outages, damage to equipment and property, and injury or death, as well as increasing the likelihood of damage to fuel lines, which can create an unsafe and potentially explosive condition. 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 and related systems can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance. Upgrades and improvements to computer systems and networks may require substantial amounts of management’s time and financial resources to complete, and may also result in system or network defects or operational errors due to the inexperience of using a new or upgraded system.

PHI is replacing customers’ existing electric and gas meters with an 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 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.

A recent court decision involving lease transactions could impact our ongoing litigation against the IRS involving certain cross-border energy lease investments, which may have a material negative impact on our results of operations and financial condition. (PHI only).

PCI maintains a portfolio of cross-border energy lease investments involving public utility assets located outside of the United States, which as of March 31, 2013, had a net investment value of approximately $869 million. PHI’s cross-border energy lease investments, each of which is with a tax-indifferent party, have been under examination by the IRS as part of normal PHI federal income tax audits. In connection with the audits of PHI’s federal income tax returns from 2001 to 2008, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to its cross-border energy lease investments. In addition, the IRS has sought to recharacterize the leases as loan transactions. PHI commenced litigation in the U.S. Court of Federal Claims in January 2012 regarding the disallowance of certain tax benefits claimed by PHI on its federal tax returns for 2001 and 2002.

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On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with a lease-in, lease-out transaction. Under applicable accounting standards, the financial statement recognition of the tax benefits of PHI’s uncertain tax position associated with the cross-border energy lease investments is permitted only if it is more likely than not that the position will be sustained. Further, the carrying value of the cross-border energy lease investments must be recalculated if there is a change or a projected change in the timing of the estimated tax benefits generated from these investments.

After analyzing the Consolidated Edison ruling, PHI has determined that its tax position with respect to the tax benefits associated with the cross-border energy leases no longer meets the more-likely-than-not standard of recognition for accounting purposes. Accordingly, PHI has recorded a non-cash charge of $377 million (after-tax) in the first quarter of 2013, consisting of a charge to reduce the carrying value of the cross-border energy lease investments and a charge to reflect the anticipated additional interest expense related to changes in its estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed.

After consideration of certain tax benefits arising from matters unrelated to these lease investments, PHI estimated that, as of March 31, 2013, it would have been obligated to pay approximately $192 million in additional federal and state taxes and approximately $50 million of interest on the additional federal and state taxes. In order to mitigate PHI’s ongoing interest costs associated with the $242 million estimate of additional taxes and interest, PHI made a deposit with the IRS of $242 million in the first quarter of 2013. While PHI presently believes that it is more likely than not that no penalty will be incurred, the IRS could require PHI to pay a penalty of up to 20% of the amount of additional taxes due. PHI continues to weigh its options with respect to its litigation with the IRS.

In March 2013, PHI began to pursue the early termination of its remaining cross-border energy lease investments with the respective lessees. PHI estimates that the early termination of the remaining cross-border energy lease investments could be accomplished during 2013; however, negotiations with the respective lessees may take longer than anticipated. While PHI cannot determine the amount of proceeds that would be realized upon the early termination of the cross-border energy lease investments or the aggregate financial impact thereof, management believes that any gains or losses incurred in the aggregate will not be material; however, there may be individual lease terminations that result in offsetting material gains and losses.

PHI’s subsidiaries are subject to collective bargaining agreements that could impact their business and operations.

As of December 31, 2012, 54% of employees of PHI and its subsidiaries, collectively, were represented by various labor unions. PHI’s subsidiaries are parties to five collective bargaining agreements with four local unions that represent these employees. Collective bargaining agreements are generally renegotiated every three to five years, and the risk exists that there could be a work stoppage after expiration of an agreement until a new collective bargaining agreement has been reached. Labor negotiations typically involve bargaining over wages, benefits and working conditions, including management rights. PHI’s last work stoppage, a two-week strike by DPL’s employees, occurred in 2010. During that strike, DPL used management and contractor employees to maintain essential operations.

One of the collective bargaining agreements to which PHI’s subsidiaries are a party will expire on June 25, 2013. Though PHI believes that a protracted work stoppage is unlikely, such an event could result in a disruption of the operations of the affected utility, which could, in turn, have a material adverse effect upon the business, results of operations, cash flow and financial condition of the affected utility and PHI.

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The agreements that govern PHI’s primary credit facility and its term loan agreement contain a consolidated indebtedness covenant that may limit discretion of each borrower to incur indebtedness or reduce its equity.

Under the terms of PHI’s primary credit facility, of which each Reporting Company is a borrower, and of PHI’s term loan agreement, the consolidated indebtedness of a borrower cannot exceed 65% of its consolidated capitalization. If a borrower’s equity were to decline or its debt were to increase to a level that caused its debt to exceed this limit, lenders under the credit facility would be entitled to refuse any further extension of credit and to declare all of the outstanding debt under the credit facility immediately due and payable. To avoid such a default, a waiver or renegotiation of this covenant would be required, which would likely increase funding costs and could result in additional covenants that would restrict the affected Reporting Company’s operational and financing flexibility.

Each borrower’s ability to comply with this covenant is subject to various risks and uncertainties, including events beyond the borrower’s control. For example, events that could cause a reduction in PHI’s equity include, without limitation, a further write-down of PHI’s cross-border energy lease investments or a significant write-down of PHI’s goodwill. Even if each borrower is able to comply with this covenant, the restrictions on its ability to operate its business in its sole discretion could harm its and PHI’s business by, among other things, limiting the borrower’s ability to incur indebtedness or reduce equity in connection with financings or other corporate opportunities that it may believe would be in its best interests or the interests of PHI’s stockholders to complete.

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

Pepco Holdings

The following table includes shares of common stock accepted by Pepco Holdings during the quarter ended March 31, 2013 from certain employees in accordance with the provisions of the Pepco Holdings Long-Term Incentive Plan (LTIP) to satisfy the employees’ minimum statutory tax withholding obligations related to vested awards of restricted stock and restricted stock units under the LTIP that were paid during such quarter. Pepco Holdings does not currently have any publicly announced plans or programs to repurchase its common stock.

Period	Total Number of Shares Accepted (a)		Average Price Per Share
January 1 – January 31, 2013		49,842	$	19.23	(b)
February 1 – February 28, 2013		80,185	$	20.37	(c)
March 1 – March 31, 2013		—		—
Total		130,027	$	19.93

(a) Includes shares of Pepco Holdings’ common stock accepted from certain employees under the LTIP to satisfy the employees’ minimum statutory tax withholding obligations related to vested LTIP awards, which shares were then held in treasury.

(b) Represents the average of the low and high trading prices of a share of common stock on the New York Stock Exchange (NYSE) on the trading day immediately preceding the vesting date.

(c) Represents the average of the low and high trading prices of a share of common stock on the NYSE on the vesting date.

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.

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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. MINE SAFETY DISCLOSURES

Not applicable.

Item 5. OTHER INFORMATION

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

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Item 6. EXHIBITS

The documents listed below are being filed or furnished on behalf of 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’s Form 10-Q, May 5, 2006.
3.3	Pepco	Restated Articles of Incorporation and Articles of Restatement (as filed in Virginia)	Exhibit 3.3 to PHI’s Form 10-Q, November 4, 2011.
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)	Exhibit B.8.1 to PHI’s Amendment No. 1 to Form U5B, February 13, 2003.
3.6	PHI	Bylaws	Exhibit 3.6 to PHI’s Form 10-K, March 1, 2013.
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.
4.1	Pepco	Supplemental Indenture, dated as of March 11, 2013, with respect to the Mortgage and Deed of Trust, dated July 1, 1936	Exhibit 4.2 to Pepco’s Form 8-K, March 12, 2013.
4.2	Pepco	Form of First Mortgage Bond, 4.15% Series due March 15, 2043 (included in Exhibit 4.1 hereto)	—
4.3	PHI	Form of Term Loan Note (included in Exhibit 10.2 hereto)	—
10.1	Pepco	Purchase Agreement, dated March 11, 2013, among Pepco, Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Scotia Capital (USA) Inc., as representatives of the several underwriters named therein	Exhibit 1.1 to Pepco’s Form 8-K, March 12, 2013.
10.2	PHI	$250,000,000 Term Loan Agreement, dated March 28, 2013, by and among Pepco Holdings, JPMorgan Chase Bank, N.A., as Administrative Agent, The Bank of Nova Scotia, as Documentation Agent, and the lenders party thereto	Exhibit 10 to PHI’s Form 8-K, March 28, 2013.
10.3	PHI	Form of 2013 Restricted Stock Unit Agreement (Time Vested) under the PHI 2012 Long-Term Incentive Plan for Joseph M. Rigby	Filed herewith.
10.4	PHI	Form of 2013 Restricted Stock Unit Agreement (Time Vested) under the PHI 2012 Long-Term Incentive Plan for Kevin C. Fitzgerald	Filed herewith.
10.5	PHI	Form of 2013 Restricted Stock Unit Agreement (Time Vested) under the PHI 2012 Long-Term Incentive Plan	Exhibit 10.50 to PHI’s Form 10-K, March 1, 2013.
10.6	PHI	Form of 2013 Restricted Stock Unit Agreement (Performance Based/162(m)) under the PHI 2012 Long-Term Incentive Plan	Exhibit 10.51 to PHI’s Form 10-K, March 1, 2013.
10.7	PHI	Form of 2013 Restricted Stock Unit Agreement (Performance Based/Non-162(m)) under the PHI 2012 Long-Term Incentive Plan	Exhibit 10.52 to PHI’s Form 10-K, March 1, 2013.

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Exhibit No.	Registrant(s)	Description of Exhibit	Reference
10.8	PHI	Form of 2013 Restricted Stock Unit Agreement (Performance Based/162(m)) under the PHI 2012 Long-Term Incentive Plan for Joseph M. Rigby	Filed herewith.
10.9	PHI	Form of 2013 Restricted Stock Unit Agreement (Performance Based/162(m)) under the PHI 2012 Long-Term Incentive Plan for Kevin C. Fitzgerald	Filed herewith.
10.10	PHI	Form of Election with Respect to Stock Tax Withholding	Exhibit 10.39 to PHI’s Form 10-K, March 1, 2013.
10.11	PHI	PHI Named Executive Officer 2013 Compensation Determinations	Exhibit 10.40 to PHI’s Form 10-K, March 1, 2013.
12.1	PHI	Statements Re: Computation of Ratios	Filed herewith.
12.2	Pepco	Statements Re: Computation of Ratios	Filed herewith.
12.3	DPL	Statements Re: Computation of Ratios	Filed herewith.
12.4	ACE	Statements Re: Computation of Ratios	Filed herewith.
31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.
31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.
32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.
101. INS	PHI Pepco DPL ACE	XBRL Instance Document	Filed herewith.
101. SCH	PHI Pepco DPL ACE	XBRL Taxonomy Extension Schema Document	Filed herewith.
101. CAL	PHI Pepco DPL ACE	XBRL Taxonomy Extension Calculation Linkbase Document	Filed herewith.
101. DEF	PHI Pepco DPL ACE	XBRL Taxonomy Extension Definition Linkbase Document	Filed herewith.

177

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
101. LAB	PHI Pepco DPL ACE	XBRL Taxonomy Extension Label Linkbase Document	Filed herewith.
101. PRE	PHI Pepco DPL ACE	XBRL Taxonomy Extension Presentation Linkbase Document	Filed 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 PHI, those of its subsidiaries that are currently registrants, Conectiv and ACE Funding 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)

Conectiv (File No. 001-13895)

Atlantic City Electric Transition Funding LLC (File No. 333-59558)

Certain instruments defining the rights of the holders of long-term debt of Pepco have not been filed as exhibits in accordance with Regulation S-K Item 601(b)(4)(iii) because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis. Pepco agrees to furnish to the SEC upon request a copy of any such instruments omitted by it.

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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)
May 2, 2013	By	/s/ FREDERICK J. BOYLE
		Frederick J. Boyle
		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)	Exhibit 3.3 to PHI’s Form 10-Q, November 4, 2011.
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)	Exhibit B.8.1 to PHI’s Amendment No. 1 to Form U5B, February 13, 2003.
3.6	PHI	Bylaws	Exhibit 3.6 to PHI’s Form 10-K, March 1, 2013.
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.
4.1	Pepco	Supplemental Indenture, dated as of March 11, 2013, with respect to the Mortgage and Deed of Trust, dated July 1, 1936	Exhibit 4.2 to Pepco’s Form 8-K, March 12, 2013.
4.2	Pepco	Form of First Mortgage Bond, 4.15% Series due March 15, 2043 (included in Exhibit 4.1 hereto)	—
4.3	Pepco	Form of Term Loan Note (included in Exhibit 10.2 hereto)	—
10.1	Pepco	Purchase Agreement, dated March 11, 2013, among Pepco, Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Scotia Capital (USA) Inc., as representatives of the several underwriters therein	Exhibit 1.1 to Pepco’s Form 8-K, March 12, 2013.
10.2	PHI	$250,000,000 Term Loan Agreement, dated March 28, 2013, by and among Pepco Holdings, JPMorgan Chase Bank, N.A., as Administrative Agent, The Bank of Nova Scotia, as Documentation Agent, and the lenders party thereto	Exhibit 10 to PHI’s Form 8-K, March 28, 2013.
10.3	PHI	Form of 2013 Restricted Stock Unit Agreement (Time Vested) under the PHI 2012 Long-Term Incentive Plan for Joseph M. Rigby	Filed herewith.
10.4	PHI	Form of 2013 Restricted Stock Unit Agreement (Time Vested) under the PHI 2012 Long-Term Incentive Plan for Kevin C. Fitzgerald	Filed herewith.
10.5	PHI	Form of 2013 Restricted Stock Unit Agreement (Time Vested) under the PHI 2012 Long-Term Incentive Plan	Exhibit 10.50 to PHI’s Form 10-K, March 1, 2013.
10.6	PHI	Form of 2013 Restricted Stock Unit Agreement (Performance Based/162(m)) under the PHI 2012 Long-Term Incentive Plan	Exhibit 10.51 to PHI’s Form 10-K, March 1, 2013.
10.7	PHI	Form of 2013 Restricted Stock Unit Agreement (Performance Based/Non 162(m)) under the PHI 2012 Long-Term Incentive Plan	Exhibit 10.52 to PHI’s Form 10-K, March 1, 2013.
10.8	PHI	Form of 2013 Restricted Stock Unit Agreement (Performance Based/162(m)) under the PHI 2012 Long-Term Incentive Plan for Joseph M. Rigby	Filed herewith.

Exhibit No.	Registrant(s)	Description of Exhibit	Reference
10.9	PHI	Form of 2013 Restricted Stock Unit Agreement (Performance Based/162(m)) under the PHI 2012 Long-Term Incentive Plan for Kevin C. Fitzgerald	Filed herewith.
10.10	PHI	Form of Election with Respect to Stock Tax Withholding	Exhibit 10.39 to PHI’s Form 10-K, March 1, 2013.
10.11	PHI	PHI Named Executive Officer 2013 Compensation Determinations	Exhibit 10.40 to PHI’s Form 10-K, March 1, 2013.
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.
101.INS	PHI Pepco DPL ACE	XBRL Instance Document	Filed herewith.
101.SCH	PHI Pepco DPL ACE	XBRL Taxonomy Extension Schema Document	Filed herewith.
101.CAL	PHI Pepco DPL ACE	XBRL Taxonomy Extension Calculation Linkbase Document	Filed herewith.
101.DEF	PHI Pepco DPL ACE	XBRL Taxonomy Extension Definition Linkbase Document	Filed herewith.
101.LAB	PHI Pepco DPL ACE	XBRL Taxonomy Extension Label Linkbase Document	Filed herewith.
101.PRE	PHI Pepco DPL ACE	XBRL Taxonomy Extension Presentation Linkbase Document	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

EX-10.3

Exhibit 10.3

PEPCO HOLDINGS, INC.

RESTRICTED STOCK UNIT AGREEMENT

(Time-Vested)

THIS RESTRICTED STOCK UNIT AGREEMENT (this “Agreement”) is effective this          day of                     , 2013 (the “Date of Grant”), by and between Pepco Holdings, Inc. (the “Company”), and Joseph M. Rigby, an employee of the Company (the “Participant”).

WHEREAS, the Company has adopted the Pepco Holdings, Inc. 2012 Long-Term Incentive Plan, as it may be amended, amended and restated and/or restated from time to time (the “Plan”).

WHEREAS, on                     , 2013, the Committee granted to the Participant a Service-Based Award of                      Restricted Stock Units under the Plan (the “RSU Award”).

WHEREAS, the Company desires to enter into an agreement with the Participant evidencing the grant to the Participant of the RSU Award approved by the Committee on the terms and conditions set forth herein.

NOW, THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the Company and the Participant agree as follows:

1. Restricted Stock Unit Award. The RSU Award is a Service-Based Award under the Plan consisting of                      Restricted Stock Units. The Restricted Stock Units are notional units of measurement denominated in shares of Stock (i.e., one Restricted Stock Unit is equivalent in value to one share of Stock, subject to the terms hereof). The Restricted Stock Units represent an unfunded, unsecured contractual right.

2. Vesting. Except as may otherwise be provided by Section 24, this RSU Award shall vest, as follows:

(a) On                     , 2016 (the “Vesting Date”), this RSU Award shall vest in full, provided that the Participant remains continuously employed by the Company or a Subsidiary beginning on the Date of Grant and ending on the Vesting Date. Except as otherwise provided by Section 2(b), 2(c) or 3 hereof, if the employment of the Participant by the Company or any Subsidiary terminates prior to the Vesting Date, this RSU Award shall be immediately forfeited in its entirety. The period beginning on the Date of Grant and ending on the Vesting Date shall be referred to herein as the “Restriction Period.”

(b) Upon (i) the Termination of the Participant’s employment without Cause, or (ii) the death or Disability of the Participant during the Restriction Period and prior to any termination of the Participant’s employment with the Company or any Subsidiary, a portion of the RSU Award shall vest, which portion shall equal the number of Restricted Stock Units covered by this Agreement multiplied by a fraction, the numerator of which shall be the number of days in the Restriction Period during which the Participant was continuously employed by the Company or a Subsidiary, and the denominator of which shall be the total number of days in the Restriction Period. The remaining portion of this RSU Award shall immediately be forfeited.

(c) The Committee may, in its sole discretion, provide that, upon the retirement of the Participant (as determined by the Committee in its sole discretion), all or part of the Restricted Stock Units covered by this RSU Award shall vest. Any such action by the Committee must be made in writing prior to the effective date of the Participant’s retirement.

Any Restricted Stock Units associated with this RSU Award as to which the vesting requirement of this Section 2 has been satisfied shall be payable in accordance with Section 5 hereof.

3. Accelerated Vesting. Notwithstanding the foregoing (but subject to compliance with the provisions of Section 17 hereof and except as may otherwise be provided in Section 24 hereof), if the Participant is terminated by the Company or a Subsidiary as an employee or if the Participant terminates such employment for Good Reason, in each case within 12 months following a Change in Control and within the Restriction Period, all of the Restricted Stock Units represented hereby shall vest upon such termination and be payable in accordance with Section 5 hereof.

4. Dividend Equivalents. Dividend Equivalents under the Plan have been granted in conjunction with this RSU Award, such that any dividend paid in cash on shares of Stock will be credited to the Participant as Dividend Equivalents as if the Restricted Stock Units represented hereby were outstanding shares of Stock. Such credit shall be made in the form of additional whole and/or fractional Restricted Stock Units, based on the Fair Market Value of the Stock on the trading day immediately prior to the date of payment of any such dividend. All such additional Restricted Stock Units shall be subject to the same vesting and forfeiture provisions applicable to the Restricted Stock Units in respect of which they were credited and shall be paid in accordance with Section 5 hereof.

5. Payment of Award. Except as otherwise provided by Section 24 hereof, payment of vested Restricted Stock Units (which shall include Restricted Stock Units credited pursuant to Dividend Equivalents described in Section 4) shall be made within thirty (30) days following the earlier of (i) the Vesting Date; or (ii) the vesting of this RSU Award in whole or in part pursuant to Sections 2(b), 2(c) or 3 hereof, but subject in each case, as applicable, to any delay that may be required under Section 16 hereof. The vested Restricted Stock Units shall be paid in the form of one share of Stock for each Restricted Stock Unit, minus deductions for applicable minimum statutory withholding taxes as set forth in Section 11 of this Agreement.

6. Nontransferability of Award. None of the Restricted Stock Units covered hereby (including any Dividend Equivalents described in Section 4) may be assigned or alienated, and shall not be subject to attachment or other legal process except (i) to the extent specifically mandated and directed by applicable state or Federal statute; or (ii) as provided in Section 11 this Agreement with respect to withholding of applicable taxes. Any attempted disposition of this RSU Award or the Restricted Stock Units (or any interest herein) in violation of this Section 6 shall be null and void.

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7. Terms and Conditions. The terms and conditions included in the Plan are incorporated herein by reference, and to the extent that any conflict or ambiguity may exist between the terms and conditions included in this Agreement and the terms and conditions included in the Plan, the terms and conditions included in the Plan shall control. By execution of this Agreement, the Participant acknowledges receipt of a copy of the Plan and further agrees to be bound thereby and by the actions of the Committee and/or the Board pursuant to the Plan.

8. No Rights as a Stockholder. The Restricted Stock Units granted pursuant to this RSU Award, whether or not vested, will not confer any voting rights or any other rights of a stockholder of the Company upon the Participant, and the Participant will not acquire any voting rights or any other rights of a stockholder of the Company unless and until such Restricted Stock Units have vested and shares of Stock underlying such Restricted Stock Units have been issued and delivered to the Participant. The Company shall not be required to issue or transfer any certificates representing shares of Stock upon vesting of the RSU Award until all applicable requirements of any law, rule or regulation have been compiled with, and any required government agency approvals have been obtained. Further, no issue or transfer of such certificates shall occur until such shares of Stock have been duly listed on any securities exchange on which the Stock may then be listed.

9. Stock Issuable Upon Vesting. Upon vesting of the RSU Award and payment of Stock pursuant to Section 5 hereof, the Participant shall be provided with the certificate(s) or certificate number(s) evidencing ownership of the shares of such Stock, subject to the implementation of an arrangement with the Participant to effectuate all necessary tax withholding. If the shares of Stock evidenced by such certificate(s) were not offered and sold to the Participant in a transaction registered under the Securities Act of 1933, as amended (the “Securities Act”), the certificate(s) may include a legend noting that the Stock may not be sold or transferred by the Participant unless such Stock is registered for resale or unless the Participant meets an exemption from registration under the Securities Act. The Company shall follow all requisite procedures to deliver such certificates to the Participant; provided, however, that such delivery may be postponed to enable the Company to comply with any applicable procedures, regulations or listing requirements of any government agency, stock exchange, transfer agent or regulatory agency.

10. No Employment Right; Tenure. This Agreement shall not constitute a contract of employment between the Company or any Subsidiary and the Participant. The Participant’s right, if any, to serve the Company as a director, officer, employee or otherwise shall not be enlarged or otherwise affected by this Agreement or his or her designation as a participant under the Plan.

11. Tax Withholding. The Participant acknowledges this RSU Award may give rise to a tax liability and a withholding obligation associated therewith, and that no shares of Stock shall be issuable to the Participant hereunder until such withholding obligation is satisfied in full. In accordance with Section 19.C. of the Plan, the Company or a Subsidiary may withhold up to, but no more than, the minimum applicable statutory federal, state and/or local taxes (collectively, “Tax Withholding Requirements”) at such time and upon such terms and conditions as required by law or determined by the Company or a Subsidiary. Subject to compliance with any requirements of applicable law, the Participant shall have all or any portion of any Tax Withholding Requirements that may be payable in respect of the RSU Award satisfied when due

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through the payment by the Participant of cash to the Company or a Subsidiary, funded by the disposition on the Participant’s behalf or for the Participant’s account of shares of Stock which would otherwise be delivered to the Participant having an aggregate fair market value equal to the aggregate amount of such Tax Withholding Requirements.

12. Securities Law Compliance. The Company currently has an effective registration statement on file with the Securities and Exchange Commission with respect to the shares of Stock subject to the RSU Award. The Company intends to maintain the effectiveness of this registration statement but has no obligation to the Participant to do so. If the registration statement ceases to be effective, the Participant will not be able to transfer or sell shares of Stock, which were issued to the Participant pursuant to the RSU Award at a time that such registration statement was not effective, unless exemptions from registration under applicable securities laws are available. Such exemptions from registration are very limited and might not be available. The Participant agrees that any resale of shares of Stock issued pursuant to the RSU Award shall comply in all respects with the requirements of all applicable securities laws, rules and regulations (including, without limitation, the provisions of the Securities Act and the Securities Exchange Act of 1934, and the respective rules and regulations promulgated thereunder) and any other law, rule or regulation applicable thereto, as such laws, rules, and regulations may be amended from time to time. The Company shall not be obligated to either issue shares of Stock or permit the resale of any such shares if such issuance or resale would violate any such requirements.

13. Other Plans and Agreements. Any gain realized by the Participant pursuant to this Agreement shall not be taken into account as compensation in the determination of the Participant’s benefits under any pension, savings, group insurance, or other benefit plan maintained by the Company or a Subsidiary, except as determined by the board of directors of such company or as expressly provided under the terms of such other plan. The Participant acknowledges that receipt of this Agreement or any prior agreement under the Plan shall not entitle the Participant to any other benefits under the Plan or any plans maintained by the Company or a Subsidiary.

14. Committee Authority. The Committee shall have complete discretion in the exercise of its rights, powers, and duties under this Agreement and the Plan. Any interpretation or construction of any provision of, and the determination of any question arising under, this Agreement shall be made by the Committee in its sole discretion and shall be final, conclusive, and binding. The Committee may designate any individual or individuals to perform any of its functions hereunder.

15. Changes in Capitalization. The Restricted Stock Units under this RSU Award shall be subject to the provisions of Section 19.H. of the Plan relating to adjustments for changes to the Company’s capitalization. The RSU Award shall not affect the right of the Company or any Subsidiary to reclassify, recapitalize or otherwise change its capital or debt structure or to merge, consolidate, convey any or all of its assets, dissolve, liquidate, windup or otherwise reorganize.

16. Section 409A. This Agreement shall be interpreted to ensure, to the fullest extent possible, that the payments contemplated hereby comply with Section 409A of the Internal Revenue Code of 1986, as amended, including the Treasury Regulations promulgated thereunder

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(“Section 409A”). However, if the RSU Award is determined to be subject to Section 409A and any payment is triggered by a separation from service, the payment will, if the Participant is a specified employee (as determined under Section 409A) and to the extent required by Section 409A, be delayed until the date that is one day after the six month anniversary of such separation from service.

17. Clawback Rules. If the Participant is subject to the provisions of (i) Section 304 of the Sarbanes-Oxley Act of 2002; (ii) any policies adopted by the Company in accordance with rules that may be promulgated by the Securities and Exchange Commission pursuant to Section 10D of the Securities Exchange Act of 1934, as amended; and (iii) any other existing or future applicable law, rule, regulation, stock exchange rule, or policy of the Board providing for the forfeiture or recoupment of equity-based compensation granted by the Company (individually or collectively, the “Clawback Rules”), this Award and the Restricted Stock Units described herein, as well as any shares of Common Stock issued hereunder (and any proceeds from the sale or disposition thereof), are subject to potential forfeiture or “clawback” to the fullest extent called for by the Clawback Rules. By accepting this Award, the Participant agrees to return to the Company the full amount required by the Clawback Rules.

18. Governing Law. This Agreement shall be construed and enforced in accordance with the laws of the State of Delaware, without giving effect to the choice of law principles thereof.

19. Binding Effect. This Agreement shall inure to the benefit of, and be binding on, the Company and its successors and assigns, and the Participant and his or her heirs, administrators, executors, other legal representatives and permitted assigns, whether so expressed or not.

20. No Waiver. No waiver of any provision of this Agreement will be valid unless in writing and signed by the person against whom such waiver is sought to be enforced, nor will failure to enforce any right under this Agreement constitute a continuing waiver of the same or a waiver of any other right hereunder.

21. Further Assurances. The Participant hereby agrees to take whatever additional action and execute and deliver all agreements, instruments and other documents the Company may deem necessary or advisable to carry out or effect any of the obligations or restrictions imposed on the Participant or the RSU Award pursuant to the express provisions of the Agreement and/or the Plan.

22. Definition of Terms. Capitalized terms used herein but not otherwise defined in this Agreement shall have the meanings ascribed to them under the Plan.

23. Entire Agreement. Except as otherwise provided in Section 24, this Agreement and the Plan constitute the entire understanding and agreement between the parties hereto with regard to the subject matter hereof, and they supersede all other negotiations, understandings and representations (if any) made by and between such parties.

24. Employment Agreement. To the extent there is a conflict between the provisions of Section 2, 3 or 5 of this Agreement and that certain Employment Agreement, dated December 20, 2011, by and between the Company and the Participant (the “Employment Agreement”), the terms of the Employment Agreement shall govern.

[signatures appear on the following page]

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IN WITNESS WHEREOF, the Company has caused this Agreement to be executed by its duly authorized officer, and the Participant has hereunder set his hand, all as of this              day of                     , 2013.

ATTEST:	PEPCO HOLDINGS, INC.
By:	By:
Name:	Name:
Title:	Title:
	PARTICIPANT:
	Printed Name:     Joseph M. Rigby

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EX-10.4

Exhibit 10.4

PEPCO HOLDINGS, INC.

RESTRICTED STOCK UNIT AGREEMENT

(Time-Vested)

THIS RESTRICTED STOCK UNIT AGREEMENT (this “Agreement”) is effective this          day of                     , 2013 (the “Date of Grant”), by and between Pepco Holdings, Inc. (the “Company”), and Kevin C. Fitzgerald, an employee of the Company (the “Participant”).

WHEREAS, the Company has adopted the Pepco Holdings, Inc. 2012 Long-Term Incentive Plan, as it may be amended, amended and restated and/or restated from time to time (the “Plan”).

WHEREAS, on                     , 2013, the Committee granted to the Participant a Service-Based Award of                      Restricted Stock Units under the Plan (the “RSU Award”).

WHEREAS, the Company desires to enter into an agreement with the Participant evidencing the grant to the Participant of the RSU Award approved by the Committee on the terms and conditions set forth herein.

NOW, THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the Company and the Participant agree as follows:

1. Restricted Stock Unit Award. The RSU Award is a Service-Based Award under the Plan consisting of              Restricted Stock Units. The Restricted Stock Units are notional units of measurement denominated in shares of Stock (i.e., one Restricted Stock Unit is equivalent in value to one share of Stock, subject to the terms hereof). The Restricted Stock Units represent an unfunded, unsecured contractual right.

2. Vesting. Except as may otherwise be provided by Section 24, this RSU Award shall vest, as follows:

(a) On                     , 2016 (the “Vesting Date”), this RSU Award shall vest in full, provided that the Participant remains continuously employed by the Company or a Subsidiary beginning on the Date of Grant and ending on the Vesting Date. Except as otherwise provided by Section 2(b), 2(c) or 3 hereof, if the employment of the Participant by the Company or any Subsidiary terminates prior to the Vesting Date, this RSU Award shall be immediately forfeited in its entirety. The period beginning on the Date of Grant and ending on the Vesting Date shall be referred to herein as the “Restriction Period.”

(b) Upon (i) the Termination of the Participant’s employment without Cause, or (ii) the death or Disability of the Participant during the Restriction Period and prior to any termination of the Participant’s employment with the Company or any Subsidiary, a portion of the RSU Award shall vest, which portion shall equal the number of Restricted Stock Units covered by this Agreement multiplied by a fraction, the numerator of which shall be the number of days in the Restriction Period during which the Participant was continuously employed by the Company or a Subsidiary, and the denominator of which shall be the total number of days in the Restriction Period. The remaining portion of this RSU Award shall immediately be forfeited.

(c) The Committee may, in its sole discretion, provide that, upon the retirement of the Participant (as determined by the Committee in its sole discretion), all or part of the Restricted Stock Units covered by this RSU Award shall vest. Any such action by the Committee must be made in writing prior to the effective date of the Participant’s retirement.

Any Restricted Stock Units associated with this RSU Award as to which the vesting requirement of this Section 2 has been satisfied shall be payable in accordance with Section 5 hereof.

3. Accelerated Vesting. Notwithstanding the foregoing (but subject to compliance with the provisions of Section 17 hereof and except as may otherwise be provided in Section 24 hereof), if the Participant is terminated by the Company or a Subsidiary as an employee or if the Participant terminates such employment for Good Reason, in each case within 12 months following a Change in Control and within the Restriction Period, all of the Restricted Stock Units represented hereby shall vest upon such termination and be payable in accordance with Section 5 hereof.

4. Dividend Equivalents. Dividend Equivalents under the Plan have been granted in conjunction with this RSU Award, such that any dividend paid in cash on shares of Stock will be credited to the Participant as Dividend Equivalents as if the Restricted Stock Units represented hereby were outstanding shares of Stock. Such credit shall be made in the form of additional whole and/or fractional Restricted Stock Units, based on the Fair Market Value of the Stock on the trading day immediately prior to the date of payment of any such dividend. All such additional Restricted Stock Units shall be subject to the same vesting and forfeiture provisions applicable to the Restricted Stock Units in respect of which they were credited and shall be paid in accordance with Section 5 hereof.

5. Payment of Award. Except as otherwise provided by Section 24 hereof, payment of vested Restricted Stock Units (which shall include Restricted Stock Units credited pursuant to Dividend Equivalents described in Section 4) shall be made within thirty (30) days following the earlier of (i) the Vesting Date; or (ii) the vesting of this RSU Award in whole or in part pursuant to Sections 2(b), 2(c) or 3 hereof, but subject in each case, as applicable, to any delay that may be required under Section 16 hereof. The vested Restricted Stock Units shall be paid in the form of one share of Stock for each Restricted Stock Unit, minus deductions for applicable minimum statutory withholding taxes as set forth in Section 11 of this Agreement.

6. Nontransferability of Award. None of the Restricted Stock Units covered hereby (including any Dividend Equivalents described in Section 4) may be assigned or alienated, and shall not be subject to attachment or other legal process except (i) to the extent specifically mandated and directed by applicable state or Federal statute; or (ii) as provided in Section 11 this Agreement with respect to withholding of applicable taxes. Any attempted disposition of this RSU Award or the Restricted Stock Units (or any interest herein) in violation of this Section 6 shall be null and void.

7. Terms and Conditions. The terms and conditions included in the Plan are incorporated herein by reference, and to the extent that any conflict or ambiguity may exist between the terms and conditions included in this Agreement and the terms and conditions included in the Plan, the terms and conditions included in the Plan shall control. By execution of this Agreement, the Participant acknowledges receipt of a copy of the Plan and further agrees to be bound thereby and by the actions of the Committee and/or the Board pursuant to the Plan.

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8. No Rights as a Stockholder. The Restricted Stock Units granted pursuant to this RSU Award, whether or not vested, will not confer any voting rights or any other rights of a stockholder of the Company upon the Participant, and the Participant will not acquire any voting rights or any other rights of a stockholder of the Company unless and until such Restricted Stock Units have vested and shares of Stock underlying such Restricted Stock Units have been issued and delivered to the Participant. The Company shall not be required to issue or transfer any certificates representing shares of Stock upon vesting of the RSU Award until all applicable requirements of any law, rule or regulation have been compiled with, and any required government agency approvals have been obtained. Further, no issue or transfer of such certificates shall occur until such shares of Stock have been duly listed on any securities exchange on which the Stock may then be listed.

9. Stock Issuable Upon Vesting. Upon vesting of the RSU Award and payment of Stock pursuant to Section 5 hereof, the Participant shall be provided with the certificate(s) or certificate number(s) evidencing ownership of the shares of such Stock, subject to the implementation of an arrangement with the Participant to effectuate all necessary tax withholding. If the shares of Stock evidenced by such certificate(s) were not offered and sold to the Participant in a transaction registered under the Securities Act of 1933, as amended (the “Securities Act”), the certificate(s) may include a legend noting that the Stock may not be sold or transferred by the Participant unless such Stock is registered for resale or unless the Participant meets an exemption from registration under the Securities Act. The Company shall follow all requisite procedures to deliver such certificates to the Participant; provided, however, that such delivery may be postponed to enable the Company to comply with any applicable procedures, regulations or listing requirements of any government agency, stock exchange, transfer agent or regulatory agency.

10. No Employment Right; Tenure. This Agreement shall not constitute a contract of employment between the Company or any Subsidiary and the Participant. The Participant’s right, if any, to serve the Company as a director, officer, employee or otherwise shall not be enlarged or otherwise affected by this Agreement or his or her designation as a participant under the Plan.

11. Tax Withholding. The Participant acknowledges this RSU Award may give rise to a tax liability and a withholding obligation associated therewith, and that no shares of Stock shall be issuable to the Participant hereunder until such withholding obligation is satisfied in full. In accordance with Section 19.C. of the Plan, the Company or a Subsidiary may withhold up to, but no more than, the minimum applicable statutory federal, state and/or local taxes (collectively, “Tax Withholding Requirements”) at such time and upon such terms and conditions as required by law or determined by the Company or a Subsidiary. Subject to compliance with any requirements of applicable law, the Participant shall have all or any portion of any Tax Withholding Requirements that may be payable in respect of the RSU Award satisfied when due through the payment by the Participant of cash to the Company or a Subsidiary, funded by the disposition on the Participant’s behalf or for the Participant’s account of shares of Stock which would otherwise be delivered to the Participant having an aggregate fair market value equal to the aggregate amount of such Tax Withholding Requirements.

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12. Securities Law Compliance. The Company currently has an effective registration statement on file with the Securities and Exchange Commission with respect to the shares of Stock subject to the RSU Award. The Company intends to maintain the effectiveness of this registration statement but has no obligation to the Participant to do so. If the registration statement ceases to be effective, the Participant will not be able to transfer or sell shares of Stock, which were issued to the Participant pursuant to the RSU Award at a time that such registration statement was not effective, unless exemptions from registration under applicable securities laws are available. Such exemptions from registration are very limited and might not be available. The Participant agrees that any resale of shares of Stock issued pursuant to the RSU Award shall comply in all respects with the requirements of all applicable securities laws, rules and regulations (including, without limitation, the provisions of the Securities Act and the Securities Exchange Act of 1934, and the respective rules and regulations promulgated thereunder) and any other law, rule or regulation applicable thereto, as such laws, rules, and regulations may be amended from time to time. The Company shall not be obligated to either issue shares of Stock or permit the resale of any such shares if such issuance or resale would violate any such requirements.

13. Other Plans and Agreements. Any gain realized by the Participant pursuant to this Agreement shall not be taken into account as compensation in the determination of the Participant’s benefits under any pension, savings, group insurance, or other benefit plan maintained by the Company or a Subsidiary, except as determined by the board of directors of such company or as expressly provided under the terms of such other plan. The Participant acknowledges that receipt of this Agreement or any prior agreement under the Plan shall not entitle the Participant to any other benefits under the Plan or any plans maintained by the Company or a Subsidiary.

14. Committee Authority. The Committee shall have complete discretion in the exercise of its rights, powers, and duties under this Agreement and the Plan. Any interpretation or construction of any provision of, and the determination of any question arising under, this Agreement shall be made by the Committee in its sole discretion and shall be final, conclusive, and binding. The Committee may designate any individual or individuals to perform any of its functions hereunder.

15. Changes in Capitalization. The Restricted Stock Units under this RSU Award shall be subject to the provisions of Section 19.H. of the Plan relating to adjustments for changes to the Company’s capitalization. The RSU Award shall not affect the right of the Company or any Subsidiary to reclassify, recapitalize or otherwise change its capital or debt structure or to merge, consolidate, convey any or all of its assets, dissolve, liquidate, windup or otherwise reorganize.

16. Section 409A. This Agreement shall be interpreted to ensure, to the fullest extent possible, that the payments contemplated hereby comply with Section 409A of the Internal Revenue Code of 1986, as amended, including the Treasury Regulations promulgated thereunder (“Section 409A”). However, if the RSU Award is determined to be subject to Section 409A and any payment is triggered by a separation from service, the payment will, if the Participant is a specified employee (as determined under Section 409A) and to the extent required by Section 409A, be delayed until the date that is one day after the six month anniversary of such separation from service.

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17. Clawback Rules. If the Participant is subject to the provisions of (i) Section 304 of the Sarbanes-Oxley Act of 2002; (ii) any policies adopted by the Company in accordance with rules that may be promulgated by the Securities and Exchange Commission pursuant to Section 10D of the Securities Exchange Act of 1934, as amended; and (iii) any other existing or future applicable law, rule, regulation, stock exchange rule, or policy of the Board providing for the forfeiture or recoupment of equity-based compensation granted by the Company (individually or collectively, the “Clawback Rules”), this Award and the Restricted Stock Units described herein, as well as any shares of Common Stock issued hereunder (and any proceeds from the sale or disposition thereof), are subject to potential forfeiture or “clawback” to the fullest extent called for by the Clawback Rules. By accepting this Award, the Participant agrees to return to the Company the full amount required by the Clawback Rules.

18. Governing Law. This Agreement shall be construed and enforced in accordance with the laws of the State of Delaware, without giving effect to the choice of law principles thereof.

19. Binding Effect. This Agreement shall inure to the benefit of, and be binding on, the Company and its successors and assigns, and the Participant and his or her heirs, administrators, executors, other legal representatives and permitted assigns, whether so expressed or not.

20. No Waiver. No waiver of any provision of this Agreement will be valid unless in writing and signed by the person against whom such waiver is sought to be enforced, nor will failure to enforce any right under this Agreement constitute a continuing waiver of the same or a waiver of any other right hereunder.

21. Further Assurances. The Participant hereby agrees to take whatever additional action and execute and deliver all agreements, instruments and other documents the Company may deem necessary or advisable to carry out or effect any of the obligations or restrictions imposed on the Participant or the RSU Award pursuant to the express provisions of the Agreement and/or the Plan.

22. Definition of Terms. Capitalized terms used herein but not otherwise defined in this Agreement shall have the meanings ascribed to them under the Plan.

23. Entire Agreement. Except as provided in Section 24, this Agreement and the Plan constitute the entire understanding and agreement between the parties hereto with regard to the subject matter hereof, and they supersede all other negotiations, understandings and representations (if any) made by and between such parties.

24. Employment Agreement. To the extent there is a conflict between the provisions of Section 2, 3 or 5 of this Agreement and that certain Employment Agreement, dated September 7, 2012, by and between the Company and the Participant (the “Employment Agreement”), the terms of the Employment Agreement shall govern.

[signatures appear on the following page]

-5-

IN WITNESS WHEREOF, the Company has caused this Agreement to be executed by its duly authorized officer, and the Participant has hereunder set his hand, all as of this          day of                     , 2013.

ATTEST:	PEPCO HOLDINGS, INC.
By:	By:
Name:	Name:
Title:	Title:
	PARTICIPANT:
	Printed Name:     Kevin C. Fitzgerald

-6-

EX-10.8

Exhibit 10.8

PEPCO HOLDINGS, INC.

RESTRICTED STOCK UNIT AGREEMENT

(Performance-Based/162(m))

THIS RESTRICTED STOCK UNIT AGREEMENT (this “Agreement”) is effective this          day of                     , 2013 (the “Date of Grant”), by and between Pepco Holdings, Inc. (the “Company”), and Joseph M. Rigby, an employee of the Company (the “Participant”).

WHEREAS, the Company has adopted the Pepco Holdings, Inc. 2012 Long-Term Incentive Plan, as it may be amended, amended and restated and/or restated from time to time (the “Plan”).

WHEREAS, on                     , 2013, the Committee granted to the Participant a Performance-Based Award under the Plan of                      Restricted Stock Units (with a maximum award opportunity of                      Restricted Stock Units) (the “RSU Award”).

WHEREAS, the Company desires to enter into an agreement with the Participant on the terms and conditions hereinafter set forth, evidencing the grant to the Participant of the RSU Award approved by the Committee.

NOW, THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the Company and the Participant agree as follows:

1. Restricted Stock Unit Award.

(a) The Company hereby grants to the Participant the RSU Award consisting of                      Restricted Stock Units (with a maximum award opportunity of                      Restricted Stock Units), all as set forth on Schedule A attached hereto. The Restricted Stock Units granted by the RSU Award are notional units of measurement denominated in shares of Stock (i.e., one Restricted Stock Unit is equivalent in value to one share of Stock, subject to the terms hereof). The Restricted Stock Units represent an unfunded, unsecured contractual right.

(b) The Restricted Stock Units granted by this RSU Award are subject to the terms and conditions set forth herein, including the performance-based vesting requirements set forth on Schedule A attached hereto, and in the Plan. The performance period shall begin on January 1, 2013 and end on December 31, 2015 (the “Performance Period”), as described in more detail on Schedule A attached hereto. The performance objectives and related business criteria with respect to the Performance Period (collectively, the “Performance Goals”) and other relevant information related to this RSU Award are set forth on Schedule A attached hereto.

(c) The restriction period of this RSU Award (the “Restriction Period”) shall be concurrent with the Performance Period.

(d) The Committee has determined that this RSU Award is intended to be “performance-based compensation” as defined in Section 162(m) (“Section 162(m)”) of the Internal Revenue Code of 1986, as amended, including the Treasury Regulations promulgated thereunder (the “Code”). As such, this RSU Award shall be a Performance-Based Award under, and shall be subject to all of the related terms, conditions, limitations and requirements of, Sections 7 and 8.C. of the Plan.

2. Vesting. Except as may otherwise be provided by Section 25:

(a) Subject to compliance with Section 13, the Restricted Stock Units under this RSU Award shall vest only (i) except as provided in Section 3 hereof, to the extent that the Performance Goals are satisfied as provided in Schedule A, and (ii) except as otherwise provided in Sections 2(c), 2(d) or 3 hereof, if the Participant remains continuously employed by the Company or a Subsidiary until the end of the Performance Period.

(b) Except as otherwise provided by Sections 2(c), 2(d) or 3 hereof, if the employment of the Participant by the Company or any Subsidiary terminates prior to the end of the Restriction Period, this RSU Award shall be immediately forfeited in its entirety.

(c) Upon (i) the Termination of the Participant’s employment without Cause, or (ii) the Disability or death of the Participant during the Restriction Period and prior to any termination of the Participant’s employment with the Company or any Subsidiary, the number of Restricted Stock Units, if any, payable under this RSU Award shall equal the number of Restricted Stock Units that otherwise would be paid, if any, following the Restriction Period (based on the achievement of the Performance Goals as determined under Section 1(b)), multiplied by a fraction, (A) the numerator of which shall be the number of days in the Restriction Period during which the Participant was continuously employed by the Company or a Subsidiary, and (B) the denominator of which shall be (x) if the Participant was employed by the Company or a Subsidiary on the first day of the Restriction Period, the total number of days in the Restriction Period, or (y) in all other cases, the total number of days within the Restriction Period equal to the period of time beginning on the first day of such continuous employment and ending on the last day of the Restriction Period. The remaining portion of this RSU Award that does not vest in accordance with this Section 2(c) shall immediately be forfeited.

(d) The Committee may, in its sole discretion, provide that, upon the retirement of the Participant (as determined by the Committee in its sole discretion), all or part of the Restricted Stock Units covered by this RSU Award shall be payable under this RSU Award, subject to the satisfaction of the Performance Goals as provided in Schedule A. Any such action by the Committee must be made in writing prior to the effective date of the Participant’s retirement.

Any portion of this RSU Award as to which the vesting requirements of this Section 2 have been satisfied shall be payable in accordance with Section 5 hereof.

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3. Accelerated Vesting. Notwithstanding anything in this Agreement to the contrary (but subject to compliance with the provisions of Section 18 hereof and except as may otherwise be provided in Section 25 hereof), if the Participant is terminated by the Company or a Subsidiary as an employee, or if the Participant terminates such employment for Good Reason, in each case within 12 months following a Change in Control and within the Restriction Period, then without regard to the extent to which the Performance Goals are achieved, a portion of the target-level number of Restricted Stock Units represented hereby shall vest and be payable in accordance with Section 5 hereof, which portion shall equal such number of Restricted Stock Units multiplied by a fraction, the numerator of which shall be the number of days of the Performance Period that have elapsed as of such Change in Control (or, in the case of a termination of employment for Good Reason, as of the date of such termination), and the denominator of which shall be the total number of days in the Performance Period. For purposes of this Section 3, it will have been assumed that all of the performance-based vesting requirements have been achieved at the target, or 100% level, as provided on Schedule A attached hereto.

4. Dividend Equivalents. Dividend Equivalents under the Plan have been granted in conjunction with this RSU Award, such that any dividend paid in cash on shares of Stock will be credited to the Participant as Dividend Equivalents as if the Restricted Stock Units represented hereby were outstanding shares of Stock. Such credit shall be made in the form of additional whole and/or fractional Restricted Stock Units, based on the Fair Market Value of the Stock on the trading day immediately prior to the date of payment of any such dividend. All such additional Restricted Stock Units shall be subject to the same vesting and forfeiture requirements applicable to the Restricted Stock Units in respect of which they were credited and shall be paid in accordance with Section 5 hereof. Notwithstanding anything in this Agreement to the contrary (except Section 3), no dividends credited in the form of Restricted Stock Units shall be paid to the Participant with respect to Restricted Stock Units under this RSU Award if the Performance Goals with respect hereto have not been satisfied.

5. Payment of Award. Except as otherwise provided by Section 25 hereof, payment of vested Restricted Stock Units (which shall include Restricted Stock Units credited pursuant to Dividend Equivalents described in Section 4) shall be made within thirty (30) days following (i) the satisfaction of all of the applicable vesting requirements under Section 2 hereof and the determination of the number of Restricted Stock Units, if any, payable under this RSU Award, or (ii) accelerated vesting under Section 3 hereof; provided, however, that the timing of all payments hereunder shall be made in compliance with Section 18. The vested Restricted Stock Units shall be paid in the form of one share of Stock for each Restricted Stock Unit, minus deductions for applicable minimum statutory withholding taxes as set forth in Section 11 of this Agreement.

6. Nontransferability of Award. None of the Restricted Stock Units covered hereby (including any Dividend Equivalents described in Section 4) may be assigned or alienated, and shall not be subject to attachment or other legal process except (i) to the extent specifically mandated and directed by applicable state or Federal statute; (ii) as provided in Section 11 this Agreement with respect to withholding of applicable taxes; or (iii) pursuant to a Permitted Transfer. Any attempted disposition of this RSU Award or the Restricted Stock Units (or any interest herein) in violation of this Section 6 shall be null and void.

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7. Terms and Conditions. The terms and conditions included in the Plan are incorporated herein by reference, and to the extent that any conflict or ambiguity may exist between the terms and conditions included in this Agreement and the terms and conditions included in the Plan, the terms and conditions included in the Plan shall control. By execution of this Agreement, the Participant acknowledges receipt of a copy of the Plan and further agrees to be bound thereby and by the actions of the Committee and/or the Board pursuant to the Plan.

8. No Rights as a Stockholder. The Restricted Stock Units granted pursuant to this RSU Award, whether or not vested, will not confer any voting rights or any other rights of a stockholder of the Company upon the Participant, and the Participant will not acquire any voting rights or any other rights of a stockholder of the Company unless and until such Restricted Stock Units have vested and shares of Stock underlying such Restricted Stock Units have been issued and delivered to the Participant. The Company shall not be required to issue or transfer any certificates representing shares of Stock upon vesting of the RSU Award until all applicable requirements of any law, rule or regulation have been compiled with, and any required government agency approvals have been obtained. Further, no issue or transfer of such certificates shall occur until such shares of Stock have been duly listed on any securities exchange on which the Stock may then be listed.

9. Stock Issuable Upon Vesting. Upon vesting of the RSU Award and payment of Stock pursuant to Section 5 hereof, the Participant shall be provided with the certificate(s) or certificate number(s) evidencing ownership of the shares of such Stock, subject to the implementation of an arrangement with the Participant to effectuate all necessary tax withholding. If the shares of Stock evidenced by such certificate(s) were not offered and sold to the Participant in a transaction registered under the Securities Act of 1933, as amended (the “Securities Act”), the certificate(s) may include a legend noting that the Stock may not be sold or transferred by the Participant unless such Stock is registered for resale or unless the Participant meets an exemption from registration under the Securities Act. The Company shall follow all requisite procedures to deliver such certificates to the Participant; provided, however, that such delivery may be postponed to enable the Company to comply with any applicable procedures, regulations or listing requirements of any government agency, stock exchange, transfer agent or regulatory agency.

10. No Employment Right; Tenure. This Agreement shall not constitute a contract of employment between the Company or any Subsidiary and the Participant. The Participant’s right, if any, to serve the Company as a director, officer, employee or otherwise shall not be enlarged or otherwise affected by this Agreement or his or her designation as a participant under the Plan.

11. Tax Withholding. The Participant acknowledges this RSU Award may give rise to a tax liability and a withholding obligation associated therewith, and that no shares of Stock shall be issuable to the Participant hereunder until such withholding obligation is satisfied in full. In accordance with Section 19.C. of the Plan, the Company or a Subsidiary may withhold up to, but no more than, the minimum applicable statutory federal, state and/or local taxes (collectively, “Tax Withholding Requirements”) at such time and upon such terms and conditions as required by law or determined by the Company or a Subsidiary. Subject to compliance with any requirements of applicable law, the Participant shall have all or any portion of any Tax Withholding Requirements that may be payable in respect of the RSU Award satisfied when due

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through the payment by the Participant of cash to the Company or a Subsidiary, funded by the disposition on the Participant’s behalf or for the Participant’s account of shares of Stock which would otherwise be delivered to the Participant having an aggregate fair market value equal to the aggregate amount of such Tax Withholding Requirements.

12. Securities Law Compliance. The Company currently has an effective registration statement on file with the Securities and Exchange Commission with respect to the shares of Stock subject to the RSU Award. The Company intends to maintain the effectiveness of this registration statement but has no obligation to the Participant to do so. If the registration statement ceases to be effective, the Participant will not be able to transfer or sell shares of Stock, which were issued to the Participant pursuant to the RSU Award at a time that such registration statement was not effective, unless exemptions from registration under applicable securities laws are available. Such exemptions from registration are very limited and might not be available. The Participant agrees that any resale of shares of Stock issued pursuant to the RSU Award shall comply in all respects with the requirements of all applicable securities laws, rules and regulations (including, without limitation, the provisions of the Securities Act and the Securities Exchange Act of 1934, and the respective rules and regulations promulgated thereunder) and any other law, rule or regulation applicable thereto, as such laws, rules, and regulations may be amended from time to time. The Company shall not be obligated to either issue shares of Stock or permit the resale of any such shares if such issuance or resale would violate any such requirements.

13. Section 162(m) Compliance. Notwithstanding anything in this Agreement to the contrary (except Section 3) but in addition to the provisions contained in the Plan and in this Agreement with respect to the payment of compensation intended to comply with Section 162(m):

(a) In no event shall this RSU Award vest in whole or in part unless the Committee has certified in writing that the Performance Goals hereunder shall have been satisfied, and the retirement, Disability or death of the Participant shall serve only to reduce the number of Restricted Stock Units that may be received if and when such Performance Goals are satisfied.

(b) No adjustment that is otherwise permitted under this Agreement shall be made to this RSU Award in whole or in part if such adjustment would prevent the RSU Award (or any other Award, whether to the Participant or any other participant in the Plan) from satisfying the requirements for “performance-based compensation” of Section 162(m).

14. Other Plans and Agreements. Any gain realized by the Participant pursuant to this Agreement shall not be taken into account as compensation in the determination of the Participant’s benefits under any pension, savings, group insurance, or other benefit plan maintained by the Company or a Subsidiary, except as determined by the board of directors of such company or as expressly provided under the terms of such other plan. The Participant acknowledges that receipt of this Agreement or any prior agreement under the Plan shall not entitle the Participant to any other benefits under the Plan or any plans maintained by the Company or a Subsidiary.

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15. Committee Authority. The Committee shall have complete discretion in the exercise of its rights, powers, and duties under this Agreement and the Plan. Any interpretation or construction of any provision of, and the determination of any question arising under, this Agreement shall be made by the Committee in its sole discretion and shall be final, conclusive, and binding. The Committee may designate any individual or individuals to perform any of its functions hereunder.

16. Changes in Capitalization. The Restricted Stock Units under this RSU Award shall be subject to the provisions of Section 19.H. of the Plan relating to adjustments for changes to the Company’s capitalization. The RSU Award shall not affect the right of the Company or any Subsidiary to reclassify, recapitalize or otherwise change its capital or debt structure or to merge, consolidate, convey any or all of its assets, dissolve, liquidate, windup or otherwise reorganize.

17. Governing Law. This Agreement shall be construed and enforced in accordance with the laws of the State of Delaware, without giving effect to the choice of law principles thereof.

18. Section 409A. This Agreement shall be interpreted to ensure, to the fullest extent possible, that the payments contemplated hereby constitute short-term deferrals as determined under Section 409A of the Code (“Section 409A”). Accordingly, except as otherwise provided in Section 7.D. of the Plan, in no event shall payment be made later than the 15th day of the third month after the end of the first calendar year in which the RSU Award is no longer subject to a “substantial risk of forfeiture” within the meaning of Section 409A. However, if the RSU Award is determined to be subject to Section 409A and any payment is triggered by a separation from service, the payment will, if the Participant is a specified employee (as determined under Section 409A) and to the extent required by Section 409A, be delayed until the date that is one day after the six month anniversary of such separation from service.

19. Clawback Rules. If the Participant is subject to the provisions of (i) Section 304 of the Sarbanes-Oxley Act of 2002; (ii) any policies adopted by the Company in accordance with rules that may be promulgated by the Securities and Exchange Commission pursuant to Section 10D of the Securities Exchange Act of 1934, as amended; and (iii) any other existing or future applicable law, rule, regulation, stock exchange rule, or policy of the Board providing for the forfeiture or recoupment of equity-based compensation granted by the Company (individually or collectively, the “Clawback Rules”), this Award and the Restricted Stock Units described herein, as well as any shares of Common Stock issued hereunder (and any proceeds from the sale or disposition thereof), are subject to potential forfeiture or “clawback” to the fullest extent called for by the Clawback Rules. By accepting this Award, the Participant agrees to return to the Company the full amount required by the Clawback Rules.

20. Binding Effect. This Agreement shall inure to the benefit of, and be binding on, the Company and its successors and assigns, and the Participant and his or her heirs, administrators, executors, other legal representatives and permitted assigns, whether so expressed or not.

21. No Waiver. No waiver of any provision of this Agreement will be valid unless in writing and signed by the person against whom such waiver is sought to be enforced, nor will failure to enforce any right under this Agreement constitute a continuing waiver of the same or a waiver of any other right hereunder.

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22. Further Assurances. The Participant hereby agrees to take whatever additional action and execute and deliver all agreements, instruments and other documents the Company may deem necessary or advisable to carry out or effect any of the obligations or restrictions imposed on the Participant or the RSU Award pursuant to the express provisions of the Agreement and/or the Plan.

23. Definition of Terms. Capitalized terms used herein but not otherwise defined in this Agreement shall have the meanings ascribed to them under the Plan.

24. Entire Agreement. Except as otherwise provided in Section 25, this Agreement and the Plan constitute the entire understanding and agreement between the parties hereto with regard to the subject matter hereof, and they supersede all other negotiations, understandings and representations (if any) made by and between such parties.

25. Employment Agreement. To the extent there is a conflict between the provisions of Section 2, 3 or 5 of this Agreement and that certain Employment Agreement, dated December 20, 2011, by and between the Company and the Participant (the “Employment Agreement”), the terms of the Employment Agreement shall govern.

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IN WITNESS WHEREOF, the Company has caused this Agreement to be executed by its duly authorized officer, and the Participant has hereunder set his hand, all as of this          day of                     , 2013.

ATTEST:	PEPCO HOLDINGS, INC.
By:	By:
Name:	Name:
Title:	Title:
	PARTICIPANT:
	Printed Name:    Joseph M. Rigby

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SCHEDULE A

TERMS, CONDITIONS AND PERFORMANCE-RELATED CRITERIA

EX-10.9

Exhibit 10.9

PEPCO HOLDINGS, INC.

RESTRICTED STOCK UNIT AGREEMENT

(Performance-Based/162(m))

THIS RESTRICTED STOCK UNIT AGREEMENT (this “Agreement”) is effective this                      day of                     , 2013 (the “Date of Grant”), by and between Pepco Holdings, Inc. (the “Company”), and Kevin C. Fitzgerald, an employee of the Company (the “Participant”).

WHEREAS, the Company has adopted the Pepco Holdings, Inc. 2012 Long-Term Incentive Plan, as it may be amended, amended and restated and/or restated from time to time (the “Plan”).

WHEREAS, on                     , 2013, the Committee granted to the Participant a Performance-Based Award under the Plan of                      Restricted Stock Units (with a maximum award opportunity of                      Restricted Stock Units) (the “RSU Award”).

WHEREAS, the Company desires to enter into an agreement with the Participant on the terms and conditions hereinafter set forth, evidencing the grant to the Participant of the RSU Award approved by the Committee.

NOW, THEREFORE, in consideration of the mutual covenants hereinafter set forth and for other good and valuable consideration, the Company and the Participant agree as follows:

1. Restricted Stock Unit Award.

(a) The Company hereby grants to the Participant the RSU Award consisting of                      Restricted Stock Units (with a maximum award opportunity of                      Restricted Stock Units), all as set forth on Schedule A attached hereto. The Restricted Stock Units granted by the RSU Award are notional units of measurement denominated in shares of Stock (i.e., one Restricted Stock Unit is equivalent in value to one share of Stock, subject to the terms hereof). The Restricted Stock Units represent an unfunded, unsecured contractual right.

(b) The Restricted Stock Units granted by this RSU Award are subject to the terms and conditions set forth herein, including the performance-based vesting requirements set forth on Schedule A attached hereto, and in the Plan. The performance period shall begin on January 1, 2013 and end on December 31, 2015 (the “Performance Period”), as described in more detail on Schedule A attached hereto. The performance objectives and related business criteria with respect to the Performance Period (collectively, the “Performance Goals”) and other relevant information related to this RSU Award are set forth on Schedule A attached hereto.

(c) The restriction period of this RSU Award (the “Restriction Period”) shall be concurrent with the Performance Period.

(d) The Committee has determined that this RSU Award is intended to be “performance-based compensation” as defined in Section 162(m) (“Section 162(m)”) of the Internal Revenue Code of 1986, as amended, including the Treasury Regulations promulgated thereunder (the “Code”). As such, this RSU Award shall be a Performance-Based Award under, and shall be subject to all of the related terms, conditions, limitations and requirements of, Sections 7 and 8.C. of the Plan.

2. Vesting. Except as may otherwise be provided by Section 25:

(a) Subject to compliance with Section 13, the Restricted Stock Units under this RSU Award shall vest only (i) except as provided in Section 3 hereof, to the extent that the Performance Goals are satisfied as provided in Schedule A, and (ii) except as otherwise provided in Sections 2(c), 2(d) or 3 hereof, if the Participant remains continuously employed by the Company or a Subsidiary until the end of the Performance Period.

(b) Except as otherwise provided by Sections 2(c), 2(d) or 3 hereof, if the employment of the Participant by the Company or any Subsidiary terminates prior to the end of the Restriction Period, this RSU Award shall be immediately forfeited in its entirety.

(c) Upon (i) the Termination of the Participant’s employment without Cause, or (ii) the Disability or death of the Participant during the Restriction Period and prior to any termination of the Participant’s employment with the Company or any Subsidiary, the number of Restricted Stock Units, if any, payable under this RSU Award shall equal the number of Restricted Stock Units that otherwise would be paid, if any, following the Restriction Period (based on the achievement of the Performance Goals as determined under Section 1(b)), multiplied by a fraction, (A) the numerator of which shall be the number of days in the Restriction Period during which the Participant was continuously employed by the Company or a Subsidiary, and (B) the denominator of which shall be (x) if the Participant was employed by the Company or a Subsidiary on the first day of the Restriction Period, the total number of days in the Restriction Period, or (y) in all other cases, the total number of days within the Restriction Period equal to the period of time beginning on the first day of such continuous employment and ending on the last day of the Restriction Period. The remaining portion of this RSU Award that does not vest in accordance with this Section 2(c) shall immediately be forfeited.

(d) The Committee may, in its sole discretion, provide that, upon the retirement of the Participant (as determined by the Committee in its sole discretion), all or part of the Restricted Stock Units covered by this RSU Award shall be payable under this RSU Award, subject to the satisfaction of the Performance Goals as provided in Schedule A. Any such action by the Committee must be made in writing prior to the effective date of the Participant’s retirement.

Any portion of this RSU Award as to which the vesting requirements of this Section 2 have been satisfied shall be payable in accordance with Section 5 hereof.

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3. Accelerated Vesting. Notwithstanding anything in this Agreement to the contrary (but subject to compliance with the provisions of Section 18 hereof and except as may otherwise be provided in Section 25 hereof), if the Participant is terminated by the Company or a Subsidiary as an employee, or if the Participant terminates such employment for Good Reason, in each case within 12 months following a Change in Control and within the Restriction Period, then without regard to the extent to which the Performance Goals are achieved, a portion of the target-level number of Restricted Stock Units represented hereby shall vest and be payable in accordance with Section 5 hereof, which portion shall equal such number of Restricted Stock Units multiplied by a fraction, the numerator of which shall be the number of days of the Performance Period that have elapsed as of such Change in Control (or, in the case of a termination of employment for Good Reason, as of the date of such termination), and the denominator of which shall be the total number of days in the Performance Period. For purposes of this Section 3, it will have been assumed that all of the performance-based vesting requirements have been achieved at the target, or 100% level, as provided on Schedule A attached hereto.

4. Dividend Equivalents. Dividend Equivalents under the Plan have been granted in conjunction with this RSU Award, such that any dividend paid in cash on shares of Stock will be credited to the Participant as Dividend Equivalents as if the Restricted Stock Units represented hereby were outstanding shares of Stock. Such credit shall be made in the form of additional whole and/or fractional Restricted Stock Units, based on the Fair Market Value of the Stock on the trading day immediately prior to the date of payment of any such dividend. All such additional Restricted Stock Units shall be subject to the same vesting and forfeiture requirements applicable to the Restricted Stock Units in respect of which they were credited and shall be paid in accordance with Section 5 hereof. Notwithstanding anything in this Agreement to the contrary (except Section 3), no dividends credited in the form of Restricted Stock Units shall be paid to the Participant with respect to Restricted Stock Units under this RSU Award if the Performance Goals with respect hereto have not been satisfied.

5. Payment of Award. Except as otherwise provided by Section 25 hereof, payment of vested Restricted Stock Units (which shall include Restricted Stock Units credited pursuant to Dividend Equivalents described in Section 4) shall be made within thirty (30) days following (i) the satisfaction of all of the applicable vesting requirements under Section 2 hereof and the determination of the number of Restricted Stock Units, if any, payable under this RSU Award, or (ii) accelerated vesting under Section 3 hereof; provided, however, that the timing of all payments hereunder shall be made in compliance with Section 18. The vested Restricted Stock Units shall be paid in the form of one share of Stock for each Restricted Stock Unit, minus deductions for applicable minimum statutory withholding taxes as set forth in Section 11 of this Agreement.

6. Nontransferability of Award. None of the Restricted Stock Units covered hereby (including any Dividend Equivalents described in Section 4) may be assigned or alienated, and shall not be subject to attachment or other legal process except (i) to the extent specifically mandated and directed by applicable state or Federal statute; (ii) as provided in Section 11 this Agreement with respect to withholding of applicable taxes; or (iii) pursuant to a Permitted Transfer. Any attempted disposition of this RSU Award or the Restricted Stock Units (or any interest herein) in violation of this Section 6 shall be null and void.

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7. Terms and Conditions. The terms and conditions included in the Plan are incorporated herein by reference, and to the extent that any conflict or ambiguity may exist between the terms and conditions included in this Agreement and the terms and conditions included in the Plan, the terms and conditions included in the Plan shall control. By execution of this Agreement, the Participant acknowledges receipt of a copy of the Plan and further agrees to be bound thereby and by the actions of the Committee and/or the Board pursuant to the Plan.

8. No Rights as a Stockholder. The Restricted Stock Units granted pursuant to this RSU Award, whether or not vested, will not confer any voting rights or any other rights of a stockholder of the Company upon the Participant, and the Participant will not acquire any voting rights or any other rights of a stockholder of the Company unless and until such Restricted Stock Units have vested and shares of Stock underlying such Restricted Stock Units have been issued and delivered to the Participant. The Company shall not be required to issue or transfer any certificates representing shares of Stock upon vesting of the RSU Award until all applicable requirements of any law, rule or regulation have been compiled with, and any required government agency approvals have been obtained. Further, no issue or transfer of such certificates shall occur until such shares of Stock have been duly listed on any securities exchange on which the Stock may then be listed.

9. Stock Issuable Upon Vesting. Upon vesting of the RSU Award and payment of Stock pursuant to Section 5 hereof, the Participant shall be provided with the certificate(s) or certificate number(s) evidencing ownership of the shares of such Stock, subject to the implementation of an arrangement with the Participant to effectuate all necessary tax withholding. If the shares of Stock evidenced by such certificate(s) were not offered and sold to the Participant in a transaction registered under the Securities Act of 1933, as amended (the “Securities Act”), the certificate(s) may include a legend noting that the Stock may not be sold or transferred by the Participant unless such Stock is registered for resale or unless the Participant meets an exemption from registration under the Securities Act. The Company shall follow all requisite procedures to deliver such certificates to the Participant; provided, however, that such delivery may be postponed to enable the Company to comply with any applicable procedures, regulations or listing requirements of any government agency, stock exchange, transfer agent or regulatory agency.

10. No Employment Right; Tenure. This Agreement shall not constitute a contract of employment between the Company or any Subsidiary and the Participant. The Participant’s right, if any, to serve the Company as a director, officer, employee or otherwise shall not be enlarged or otherwise affected by this Agreement or his or her designation as a participant under the Plan.

11. Tax Withholding. The Participant acknowledges this RSU Award may give rise to a tax liability and a withholding obligation associated therewith, and that no shares of Stock shall be issuable to the Participant hereunder until such withholding obligation is satisfied in full. In accordance with Section 19.C. of the Plan, the Company or a Subsidiary may withhold up to, but no more than, the minimum applicable statutory federal, state and/or local taxes (collectively, “Tax Withholding Requirements”) at such time and upon such terms and conditions as required by law or determined by the Company or a Subsidiary. Subject to compliance with any requirements of applicable law, the Participant shall have all or any portion of any Tax Withholding Requirements that may be payable in respect of the RSU Award satisfied when due

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through the payment by the Participant of cash to the Company or a Subsidiary, funded by the disposition on the Participant’s behalf or for the Participant’s account of shares of Stock which would otherwise be delivered to the Participant having an aggregate fair market value equal to the aggregate amount of such Tax Withholding Requirements.

12. Securities Law Compliance. The Company currently has an effective registration statement on file with the Securities and Exchange Commission with respect to the shares of Stock subject to the RSU Award. The Company intends to maintain the effectiveness of this registration statement but has no obligation to the Participant to do so. If the registration statement ceases to be effective, the Participant will not be able to transfer or sell shares of Stock, which were issued to the Participant pursuant to the RSU Award at a time that such registration statement was not effective, unless exemptions from registration under applicable securities laws are available. Such exemptions from registration are very limited and might not be available. The Participant agrees that any resale of shares of Stock issued pursuant to the RSU Award shall comply in all respects with the requirements of all applicable securities laws, rules and regulations (including, without limitation, the provisions of the Securities Act and the Securities Exchange Act of 1934, and the respective rules and regulations promulgated thereunder) and any other law, rule or regulation applicable thereto, as such laws, rules, and regulations may be amended from time to time. The Company shall not be obligated to either issue shares of Stock or permit the resale of any such shares if such issuance or resale would violate any such requirements.

13. Section 162(m) Compliance. Notwithstanding anything in this Agreement to the contrary (except Section 3) but in addition to the provisions contained in the Plan and in this Agreement with respect to the payment of compensation intended to comply with Section 162(m):

(a) In no event shall this RSU Award vest in whole or in part unless the Committee has certified in writing that the Performance Goals hereunder shall have been satisfied, and the retirement, Disability or death of the Participant shall serve only to reduce the number of Restricted Stock Units that may be received if and when such Performance Goals are satisfied.

(b) No adjustment that is otherwise permitted under this Agreement shall be made to this RSU Award in whole or in part if such adjustment would prevent the RSU Award (or any other Award, whether to the Participant or any other participant in the Plan) from satisfying the requirements for “performance-based compensation” of Section 162(m).

14. Other Plans and Agreements. Any gain realized by the Participant pursuant to this Agreement shall not be taken into account as compensation in the determination of the Participant’s benefits under any pension, savings, group insurance, or other benefit plan maintained by the Company or a Subsidiary, except as determined by the board of directors of such company or as expressly provided under the terms of such other plan. The Participant acknowledges that receipt of this Agreement or any prior agreement under the Plan shall not entitle the Participant to any other benefits under the Plan or any plans maintained by the Company or a Subsidiary.

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15. Committee Authority. The Committee shall have complete discretion in the exercise of its rights, powers, and duties under this Agreement and the Plan. Any interpretation or construction of any provision of, and the determination of any question arising under, this Agreement shall be made by the Committee in its sole discretion and shall be final, conclusive, and binding. The Committee may designate any individual or individuals to perform any of its functions hereunder.

16. Changes in Capitalization. The Restricted Stock Units under this RSU Award shall be subject to the provisions of Section 19.H. of the Plan relating to adjustments for changes to the Company’s capitalization. The RSU Award shall not affect the right of the Company or any Subsidiary to reclassify, recapitalize or otherwise change its capital or debt structure or to merge, consolidate, convey any or all of its assets, dissolve, liquidate, windup or otherwise reorganize.

17. Governing Law. This Agreement shall be construed and enforced in accordance with the laws of the State of Delaware, without giving effect to the choice of law principles thereof.

18. Section 409A. This Agreement shall be interpreted to ensure, to the fullest extent possible, that the payments contemplated hereby constitute short-term deferrals as determined under Section 409A of the Code (“Section 409A”). Accordingly, except as otherwise provided in Section 7.D. of the Plan, in no event shall payment be made later than the 15th day of the third month after the end of the first calendar year in which the RSU Award is no longer subject to a “substantial risk of forfeiture” within the meaning of Section 409A. However, if the RSU Award is determined to be subject to Section 409A and any payment is triggered by a separation from service, the payment will, if the Participant is a specified employee (as determined under Section 409A) and to the extent required by Section 409A, be delayed until the date that is one day after the six month anniversary of such separation from service.

19. Clawback Rules. If the Participant is subject to the provisions of (i) Section 304 of the Sarbanes-Oxley Act of 2002; (ii) any policies adopted by the Company in accordance with rules that may be promulgated by the Securities and Exchange Commission pursuant to Section 10D of the Securities Exchange Act of 1934, as amended; and (iii) any other existing or future applicable law, rule, regulation, stock exchange rule, or policy of the Board providing for the forfeiture or recoupment of equity-based compensation granted by the Company (individually or collectively, the “Clawback Rules”), this Award and the Restricted Stock Units described herein, as well as any shares of Common Stock issued hereunder (and any proceeds from the sale or disposition thereof), are subject to potential forfeiture or “clawback” to the fullest extent called for by the Clawback Rules. By accepting this Award, the Participant agrees to return to the Company the full amount required by the Clawback Rules.

20. Binding Effect. This Agreement shall inure to the benefit of, and be binding on, the Company and its successors and assigns, and the Participant and his or her heirs, administrators, executors, other legal representatives and permitted assigns, whether so expressed or not.

21. No Waiver. No waiver of any provision of this Agreement will be valid unless in writing and signed by the person against whom such waiver is sought to be enforced, nor will failure to enforce any right under this Agreement constitute a continuing waiver of the same or a waiver of any other right hereunder.

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22. Further Assurances. The Participant hereby agrees to take whatever additional action and execute and deliver all agreements, instruments and other documents the Company may deem necessary or advisable to carry out or effect any of the obligations or restrictions imposed on the Participant or the RSU Award pursuant to the express provisions of the Agreement and/or the Plan.

23. Definition of Terms. Capitalized terms used herein but not otherwise defined in this Agreement shall have the meanings ascribed to them under the Plan.

24. Entire Agreement. Except as otherwise provided in Section 25, this Agreement and the Plan constitute the entire understanding and agreement between the parties hereto with regard to the subject matter hereof, and they supersede all other negotiations, understandings and representations (if any) made by and between such parties.

25. Employment Agreement. To the extent there is a conflict between the provisions of Section 2, 3 or 5 of this Agreement and that certain Employment Agreement, dated September 7, 2012, by and between the Company and the Participant (the “Employment Agreement”), the terms of the Employment Agreement shall govern.

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IN WITNESS WHEREOF, the Company has caused this Agreement to be executed by its duly authorized officer, and the Participant has hereunder set his hand, all as of this          day of                     , 2013.

ATTEST:	PEPCO HOLDINGS, INC.
By:	By:
Name:	Name:
Title:	Title:
	PARTICIPANT:
	Printed Name:    Kevin C. Fitzgerald

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SCHEDULE A

TERMS, CONDITIONS AND PERFORMANCE-RELATED CRITERIA

EX-12.1

Exhibit 12.1

PEPCO HOLDINGS, INC.

				For the Year Ended December 31,
	Three Months Ended March 31, 2013			2012			2011		2010		2009
	(millions of dollars)
(Loss) Earnings
Net (Loss) income from continuing operations	$	(430	)	$	272		$	247	$	136	$	220
Preferred stock dividend		—			—			—		—		—
(Income) or loss from equity investees		(1	)		(1	)		3		1		(2	)
Minority interest loss		—			—			—		—		—
Income tax expense related to continuing operations		135			148			140		9		103
Pre-tax (loss) income for common stock		(296	)		419			390		146		321
Add: Fixed charges*		75			294			287		336		369
Add: Distributed income of equity investees		—			—			—		—		—
Subtract: Interest capitalized		—			—			—		—		—
Subtract: Pre-tax preferred stock dividend requirement		—			—			—		—		—
(Loss) Earnings	$	(221	)	$	713		$	677	$	482	$	690
*Fixed Charges
Interest on long-term debt	$	65		$	257		$	251	$	293	$	323
Interest capitalized		—			—			—		—		—
Other interest		—			—			—		—		—
Amortization of debt discount, premium, and expense		4			16			14		21		23
Interest component of rentals		6			21			22		22		23
Pre-tax preferred stock dividend requirement		—			—			—		—		—
Fixed charges	$	75		$	294		$	287	$	336	$	369
Ratio of (loss) earnings to fixed charges		(2.95	)		2.43			2.36		1.43		1.87

(a) Pepco Holdings, Inc. has no preferred equity securities outstanding, therefore the ratio of earnings to fixed charges is equal to the ratio of earnings to combined fixed charges and preferred stock dividends.

EX-12.2

Exhibit 12.2

POTOMAC ELECTRIC POWER COMPANY

			For the Year Ended December 31,
	Three Months Ended March 31, 2013		2012		2011		2010		2009
	(millions of dollars)
Earnings
Net income for common stock	$	23	$	126	$	99	$	108	$	106
Preferred stock dividend		—		—		—		—		—
(Income) or loss from equity investees		—		—		—		—		—
Minority interest loss		—		—		—		—		—
Income tax expense		2		48		36		37		76
Pre-tax income for common stock		25		174		135		145		182
Add: Fixed charges*		29		113		111		111		114
Add: Distributed income of equity investees		—		—		—		—		—
Subtract: Interest capitalized		—		—		—		—		—
Subtract: Pre-tax preferred stock dividend requirement		—		—		—		—		—
Earnings	$	54	$	287	$	246	$	256	$	296
*Fixed Charges
Interest on long-term debt	$	26	$	101	$	97	$	97	$	99
Interest capitalized		—		—		—		—		—
Other interest		—		—		—		—		—
Amortization of debt discount, premium, and expense		1		5		4		4		4
Interest component of rentals		2		7		10		10		11
Pre-tax preferred stock dividend requirement		—		—		—		—		—
Fixed charges	$	29	$	113	$	111	$	111	$	114
Ratio of earnings to fixed charges (a)		1.86		2.54		2.22		2.31		2.60

(a) Pepco has no preferred equity securities outstanding, therefore the ratio of earnings to fixed charges is equal to the ratio of earnings to combined fixed charges and preferred stock dividends.

EX-12.3

Exhibit 12.3

DELMARVA POWER & LIGHT COMPANY

			For the Year Ended December 31,
	Three Months Ended March 31, 2013		2012		2011		2010		2009
	(millions of dollars)
Earnings
Net income for common stock	$	26	$	73	$	71	$	45	$	52
Preferred stock dividend		—		—		—		—		—
(Income) or loss from equity investees		—		—		—		—		—
Minority interest loss		—		—		—		—		—
Income tax expense		16		44		42		31		16
Pre-tax income for common stock		42		117		113		76		68
Add: Fixed charges*		14		52		49		48		47
Add: Distributed income of equity investees		—		—		—		—		—
Subtract: Interest capitalized		—		—		—		—		—
Subtract: Pre-tax preferred stock dividend requirement		—		—		—		—		—
Earnings	$	56	$	169	$	162	$	124	$	115
*Fixed Charges
Interest on long-term debt	$	12	$	45	$	42	$	43	$	42
Interest capitalized		—		—		—		—		—
Other interest		—		—		—		—		—
Amortization of debt discount, premium, and expense		1		4		4		3		3
Interest component of rentals		1		3		3		2		2
Pre-tax preferred stock dividend requirement		—		—		—		—		—
Fixed charges	$	14	$	52	$	49	$	48	$	47
Ratio of earnings to fixed charges (a)		4.00		3.25		3.31		2.58		2.45

(a) DPL has no preferred equity securities outstanding, therefore the ratio of earnings to fixed charges is equal to the ratio of earnings to combined fixed charges and preferred stock dividends.

EX-12.4

Exhibit 12.4

ATLANTIC CITY ELECTRIC COMPANY

				For the Year Ended December 31,
	Three Months Ended March 31, 2013			2012		2011		2010		2009
	(millions of dollars)
Earnings
Net income for common stock	$	9		$	35	$	39	$	53	$	41
Preferred stock dividend		—			—		—		—		—
(Income) or loss from equity investees		—			—		—		—		—
Minority interest loss		—			—		—		—		—
Income tax (benefit) expense		(3	)		18		33		43		17
Pre-tax income for common stock		6			53		72		96		58
Add: Fixed charges*		18			75		74		69		72
Add: Distributed income of equity investees		—			—		—		—		—
Subtract: Interest capitalized		—			—		—		—		—
Subtract: Pre-tax preferred stock dividend requirement		—			—		—		—		—
Earnings	$	24		$	128	$	146	$	165	$	130
*Fixed Charges
Interest on long-term debt	$	17		$	69	$	69	$	63	$	67
Interest capitalized		—			—		—		—		—
Other interest		—			—		—		—		—
Amortization of debt discount, premium, and expense		—			2		2		3		2
Interest component of rentals		1			4		3		3		3
Pre-tax preferred stock dividend requirement		—			—		—		—		—
Fixed charges	$	18		$	75	$	74	$	69	$	72
Ratio of earnings to fixed charges (a)		1.33			1.71		1.97		2.39		1.81

(a) ACE has no preferred equity securities outstanding, therefore the ratio of earnings to fixed charges is equal to the ratio of earnings to combined fixed charges and preferred stock dividends.

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Joseph M. Rigby, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 2, 2013	/s/ JOSEPH M. RIGBY
	Joseph M. Rigby
	Chairman of the Board, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Frederick J. Boyle, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 2, 2013	/s/ FREDERICK J. BOYLE
	Frederick J. Boyle
	Senior Vice President and Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION

I, David M. Velazquez, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 2, 2013	/s/ DAVID M. VELAZQUEZ
	David M. Velazquez President and Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATION

I, Frederick J. Boyle, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 2, 2013	/s/ FREDERICK J. BOYLE
	Frederick J. Boyle
	Senior Vice President and Chief Financial Officer

EX-31.5

Exhibit 31.5

CERTIFICATION

I, David M. Velazquez, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 2, 2013	/s/ DAVID M. VELAZQUEZ
	David M. Velazquez
	President and Chief Executive Officer

EX-31.6

Exhibit 31.6

CERTIFICATION

I, Frederick J. Boyle, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 2, 2013	/s/ FREDERICK J. BOYLE
	Frederick J. Boyle
	Senior Vice President and Chief Financial Officer

EX-31.7

Exhibit 31.7

CERTIFICATION

I, David M. Velazquez, certify that:

1. I have reviewed this report on Form 10-Q of Atlantic City Electric Company;

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

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

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

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

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

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

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

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

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

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

Date: May 2, 2013	/s/ DAVID M. VELAZQUEZ
	David M. Velazquez
	President and Chief Executive Officer

EX-31.8

Exhibit 31.8

CERTIFICATION

I, Frederick J. Boyle, certify that:

1. I have reviewed this report on Form 10-Q of Atlantic City Electric Company;

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

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

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

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

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

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

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

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

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

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

Date: May 2, 2013	/s/ FREDERICK J. BOYLE
	Frederick J. Boyle
	Chief Financial Officer

EX-32.1

Exhibit 32.1

Certificate of Chief Executive Officer and Chief Financial Officer

of

Pepco Holdings, Inc.

(pursuant to 18 U.S.C. Section 1350)

I, Joseph M. Rigby, and I, Frederick J. Boyle, each certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Pepco Holdings, Inc. for the quarter ended March 31, 2013, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Pepco Holdings, Inc.

May 2, 2013	/s/ JOSEPH M. RIGBY
	Joseph M. Rigby
	Chairman of the Board, President and Chief Executive Officer
May 2, 2013	/s/ FREDERICK J. BOYLE
	Frederick J. Boyle
	Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Pepco Holdings, Inc. and will be retained by Pepco Holdings, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Certificate of Chief Executive Officer and Chief Financial Officer

of

Potomac Electric Power Company

(pursuant to 18 U.S.C. Section 1350)

I, David M. Velazquez, and I, Frederick J. Boyle, each certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Potomac Electric Power Company for the quarter ended March 31, 2013, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Potomac Electric Power Company.

May 2, 2013	/s/ DAVID M. VELAZQUEZ
	David M. Velazquez
	President and Chief Executive Officer
May 2, 2013	/s/ FREDERICK J. BOYLE
	Frederick J. Boyle
	Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Potomac Electric Power Company and will be retained by Potomac Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.3

Exhibit 32.3

Certificate of Chief Executive Officer and Chief Financial Officer

of

Delmarva Power & Light Company

(pursuant to 18 U.S.C. Section 1350)

I, David M. Velazquez, and I, Frederick J. Boyle, each certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Delmarva Power & Light Company for the quarter ended March 31, 2013, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Delmarva Power & Light Company.

May 2, 2013	/s/ DAVID M. VELAZQUEZ
	David M. Velazquez
	President and Chief Executive Officer
May 2, 2013	/s/ FREDERICK J. BOYLE
	Frederick J. Boyle
	Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Delmarva Power & Light Company and will be retained by Delmarva Power & Light Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.4

Exhibit 32.4

Certificate of Chief Executive Officer and Chief Financial Officer

of

Atlantic City Electric Company

(pursuant to 18 U.S.C. Section 1350)

I, David M. Velazquez, and I, Frederick J. Boyle, each certify that, to the best of my knowledge, (i) the Quarterly Report on Form 10-Q of Atlantic City Electric Company for the quarter ended March 31, 2013, filed with the Securities and Exchange Commission on the date hereof fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Atlantic City Electric Company.

May 2, 2013	/s/ DAVID M. VELAZQUEZ
	David M. Velazquez
	President and Chief Executive Officer
May 2, 2013	/s/ FREDERICK J. BOYLE
	Frederick J. Boyle
	Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Atlantic City Electric Company and will be retained by Atlantic City Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2013

Delmarva Power & Light Co/De [Member]

Schedule Of Related Party Transactions Included In Financial Statements

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:

	Three Months Ended March  31,
	2013		2012
	(millions of dollars)
Intercompany lease transactions (a)	$	1	$	1

(a) Included in Electric revenue.

As of March 31, 2013 and December 31, 2012, DPL had the following balances on its balance sheets due to related parties:

	March 31, 2013			December 31, 2012
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(21	)	$	(19	)
Other		(1	)		(1	)
Total	$	(22	)	$	(20	)

(a) Included in Accounts Payable Due to Associated Companies.

Atlantic City Electric Co [Member]

Schedule Of Related Party Transactions Included In Financial Statements

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

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
Meter reading services provided by Millennium Account Services LLC (an ACE affiliate) (a)	$	(1	)	$	(1	)

(a) Included in Other Operation and Maintenance expense.

As of March 31, 2013 and December 31, 2012, ACE had the following balances on its consolidated balance sheets due to related parties:

	March 31, 2013			December 31, 2012
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(16	)	$	(13	)
Other		(1	)		(1	)
Total	$	(17	)	$	(14	)

(a) Included in Accounts Payable Due to Associated Companies.

Potomac Electric Power Co [Member]

Schedule Of Related Party Transactions Included In Financial Statements

	March 31, 2013			December 31, 2012
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(31	)	$	(22	)
Pepco Energy Services (b)		(17	)		(18	)
Other		(1	)		(1	)
Total	$	(49	)	$	(41	)

(a) Included in Accounts Payable Due to Associated Companies.

(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. Amount also includes charges for utility work performed by Pepco Energy Services on behalf of Pepco.

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Income Taxes (Reconciliation Of Effective Income Tax Rate From Continuing Operations) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Income Tax Rate Reconciliation [Line Items]
Income tax at Federal statutory rate	$ (103)	$ 26
State income taxes, net of Federal effect	5	4
Asset removal costs	(3)	(3)
Changes in estimates and interest related to uncertain and effectively settled tax positions	67	(13)
Cross-border energy lease investments	64	(1)
Establishment of valuation allowances related to deferred tax assets	101
Other, net	4	(2)
Consolidated income tax expense related to continuing operations	135	11
Income tax at Federal statutory rate	35.00%	35.00%
State income taxes, net of Federal effect	(1.70%)	5.40%
Asset removal costs	1.00%	(4.10%)
Changes in estimates and interest related to uncertain and effectively settled tax positions	(22.70%)	(17.60%)
Cross-border energy lease investments	(21.70%)	(1.40%)
Establishment of valuation allowances related to deferred tax assets	(34.20%)
Other, net	(1.50%)	(2.40%)
Consolidated income tax expense related to continuing operations	(45.80%)	14.90%
Potomac Electric Power Co [Member]
Income Tax Rate Reconciliation [Line Items]
Income tax at Federal statutory rate	9	7
State income taxes, net of Federal effect	2	1
Asset removal costs	(3)	(3)
Changes in estimates and interest related to uncertain and effectively settled tax positions	(5)	(10)
Other, net	(1)
Consolidated income tax expense related to continuing operations	2	(5)
Income tax at Federal statutory rate	35.00%	35.00%
State income taxes, net of Federal effect	8.00%	6.30%
Asset removal costs	(12.00%)	(15.80%)
Changes in estimates and interest related to uncertain and effectively settled tax positions	(20.00%)	(50.50%)
Other, net	(3.00%)	(1.30%)
Consolidated income tax expense related to continuing operations	8.00%	(26.30%)
Delmarva Power & Light Co/De [Member]
Income Tax Rate Reconciliation [Line Items]
Income tax at Federal statutory rate	15	12
State income taxes, net of Federal effect	2	2
Changes in estimates and interest related to uncertain and effectively settled tax positions	(1)
Other, net
Consolidated income tax expense related to continuing operations	$ 16	$ 14
Income tax at Federal statutory rate	35.00%	35.00%
State income taxes, net of Federal effect	4.70%	5.70%
Changes in estimates and interest related to uncertain and effectively settled tax positions	(2.40%)
Other, net	0.80%	(0.70%)
Consolidated income tax expense related to continuing operations	38.10%	40.00%

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Leasing Activities (Income Recognized From Cross-Border Energy Lease Investments) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Leases [Abstract]
Pre-tax income from PHI's cross-border energy lease investments (included in Other Revenue)	$ 5	$ 13
Non-cash charge to reduce carrying value of PHI's cross-border energy lease investments	(373)
Pre-tax (loss) income from PHI's cross-border energy lease investments after adjustment	(368)	13
Income tax (benefit) expense related to PHI's cross-border energy lease investments, including interest expense on uncertain tax positions	(48)	1
Net (loss) income from PHI's cross-border energy lease investments	$ (320)	$ 12

XML

Fair Value Disclosures (Gains On Level 3 Instruments Included In Income) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Total gains included in income for the period	$ 1	$ 1
Change in unrealized gains relating to assets still held at reporting date	1	1
Potomac Electric Power Co [Member]
Total gains included in income for the period	1	1
Change in unrealized gains relating to assets still held at reporting date	$ 1	$ 1

XML

Income Taxes (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Schedule Of Income Tax [Line Items]
Consolidated effective tax rates from continuing operations	(45.80%)	14.90%
Change in estimates and interest related to uncertain and effectively settled tax positions	$ 67	$ (13)
Cross-border energy lease investments	64	(1)
Establishment of valuation allowance on deferred tax assets	101
After-tax effect of revised lease rerun	377
Interest Expense [Member]
Schedule Of Income Tax [Line Items]
After-tax non-cash charge	70
Potomac Electric Power Co [Member]
Schedule Of Income Tax [Line Items]
Consolidated effective tax rates from continuing operations	8.00%	(26.30%)
Change in estimates and interest related to uncertain and effectively settled tax positions	(5)	(10)
After-tax effect of revised lease rerun	377
Additional interest income	5
Potomac Electric Power Co [Member] | Interest Expense [Member]
Schedule Of Income Tax [Line Items]
After-tax non-cash charge	70
Delmarva Power & Light Co/De [Member]
Schedule Of Income Tax [Line Items]
Consolidated effective tax rates from continuing operations	38.10%	40.00%
Change in estimates and interest related to uncertain and effectively settled tax positions	(1)
After-tax effect of revised lease rerun	377
Additional interest income	1
Delmarva Power & Light Co/De [Member] | Interest Expense [Member]
Schedule Of Income Tax [Line Items]
After-tax non-cash charge	70
Atlantic City Electric Co [Member]
Schedule Of Income Tax [Line Items]
Consolidated effective tax rates from continuing operations	(50.30%)	(100.00%)
After-tax effect of revised lease rerun	377
Additional interest income	6
Interest benefit related to uncertain and effectively settled tax positions	6
Atlantic City Electric Co [Member] | Interest Expense [Member]
Schedule Of Income Tax [Line Items]
After-tax non-cash charge	$ 70

XML

Discontinued Operations (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended			3 Months Ended		3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2013 Natural Gas [Member]	Mar. 31, 2013 Discontinued Operations [Member]	Dec. 31, 2012 Discontinued Operations [Member]	Jun. 30, 2013 Subsequent Event [Member] Discontinued Operations [Member]
Derivative [Line Items]
Other energy services receivable			$ 8
Unrealized derivative losses after tax	(2)			(2)
Pre-tax unrealized derivative losses				(4)
Expected gain upon closing of contract						8
Expected gain upon closing of contract, after tax						5
Inventory assets	153	155		1	1
Derivative liabilities				$ 8	$ 12

XML

Leasing Activities (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2013 Power Delivery [Member]	Mar. 31, 2013 Other Non-Regulated [Member]	Mar. 31, 2013 Corporate And Other [Member]	Mar. 31, 2013 Phi [Member] Agreement	Jul. 01, 2013 Phi [Member] Subsequent Event [Member]	Mar. 31, 2013 Interest Expense [Member]	Mar. 31, 2013 PHI [Member]	Dec. 31, 2012 PHI [Member]
Leases [Line Items]
Lease investments	$ 869	$ 1,237							$ 869	$ 1,237
After-tax non-cash charge	377
Non-cash charge to reduce carrying value of PHI's cross-border energy lease investments	373
After-tax effect of revised lease rerun	307
After-tax non-cash charge								70
Interest benefit			12
Interest expense on uncertain tax positions	16			16	66
Maximum percentage of penalty on the amount of additional taxes due	20.00%
Number of lease termination agreements						2
Net cash proceeds						168
Net of aggregate termination payments						804
Net pre tax loss							$ 27

XML

Equity And Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2013

Text Block [Abstract]

Schedule Of Basic And Diluted Earnings Per Share

	Three Months Ended March 31,
	2013			2012
	(millions of dollars, except per share data)
Income (Numerator):
Net (Loss) Income from continuing operations	$	(430	)	$	63
Net (Loss) Income from discontinued operations		—			5
Net (Loss) Income	$	(430	)	$	68
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		237			228
Adjustment to shares outstanding		—			—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		237			228
Net effect of potentially dilutive shares (a)		—			—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		237			228
Basic and Diluted Earnings per Share
(Loss) Earnings per share of common stock from continuing operations	$	(1.82	)	$	0.28
Earnings per share of common stock from discontinued operations		—			0.02
Basic and diluted (loss) earnings per share	$	(1.82	)	$	0.30

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS as they are considered to be anti-dilutive were zero and 3,000 for the three months ended March 31, 2013 and 2012, respectively.

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Discontinued Operations (Operating Results For Retail Natural Gas Supply Business) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Discontinued Operations And Disposal Groups [Abstract]
Income from operations of discontinued operations, net of income taxes	$ 2	$ 5
Unrealized losses associated with retail natural gas supply contracts, net of income taxes	(2)
Income From Discontinued Operations, Net of Income Taxes		$ 5

XML

Commitments And Contingencies (Schedule Of Accrued Liabilities For Environmental Exposures) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Commitments And Contingencies [Line Items]
Beginning balance	$ 29
Accruals
Payments	1
Ending balance	28
Less amounts in Other current liabilities	5
Amounts in Other deferred credits	23
Potomac Electric Power Co [Member]
Commitments And Contingencies [Line Items]
Beginning balance	17
Accruals
Payments
Ending balance	17
Less amounts in Other current liabilities	1
Amounts in Other deferred credits	16
Delmarva Power & Light Co/De [Member]
Commitments And Contingencies [Line Items]
Beginning balance	6
Accruals
Payments	1
Ending balance	5
Less amounts in Other current liabilities	4
Amounts in Other deferred credits	1
Transmission And Distribution [Member]
Commitments And Contingencies [Line Items]
Beginning balance	15
Accruals
Payments
Ending balance	15
Less amounts in Other current liabilities	2
Amounts in Other deferred credits	13
Transmission And Distribution [Member] | Potomac Electric Power Co [Member]
Commitments And Contingencies [Line Items]
Beginning balance	14
Accruals
Payments
Ending balance	14
Less amounts in Other current liabilities	1
Amounts in Other deferred credits	13
Transmission And Distribution [Member] | Delmarva Power & Light Co/De [Member]
Commitments And Contingencies [Line Items]
Beginning balance	1
Accruals
Payments
Ending balance	1
Less amounts in Other current liabilities	1
Amounts in Other deferred credits
Legacy Generation Regulated [Member]
Commitments And Contingencies [Line Items]
Beginning balance	7
Accruals
Payments	1
Ending balance	6
Less amounts in Other current liabilities	1
Amounts in Other deferred credits	5
Legacy Generation Regulated [Member] | Potomac Electric Power Co [Member]
Commitments And Contingencies [Line Items]
Beginning balance	3
Accruals
Payments
Ending balance	3
Less amounts in Other current liabilities
Amounts in Other deferred credits	3
Legacy Generation Regulated [Member] | Delmarva Power & Light Co/De [Member]
Commitments And Contingencies [Line Items]
Beginning balance	3
Accruals
Payments	1
Ending balance	2
Less amounts in Other current liabilities	1
Amounts in Other deferred credits	1
Legacy Generation Regulated [Member] | Atlantic City Electric Co [Member]
Commitments And Contingencies [Line Items]
Beginning balance	1
Accruals
Payments
Ending balance	1
Less amounts in Other current liabilities
Amounts in Other deferred credits	1
Legacy Generation Non-Regulated [Member]
Commitments And Contingencies [Line Items]
Beginning balance	5
Accruals
Payments
Ending balance	5
Less amounts in Other current liabilities
Amounts in Other deferred credits	5
Other [Member]
Commitments And Contingencies [Line Items]
Beginning balance	2
Accruals
Payments
Ending balance	2
Less amounts in Other current liabilities	2
Amounts in Other deferred credits
Other [Member] | Delmarva Power & Light Co/De [Member]
Commitments And Contingencies [Line Items]
Beginning balance	2
Accruals
Payments
Ending balance	2
Less amounts in Other current liabilities	2
Amounts in Other deferred credits

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Equity And Earnings Per Share (Narrative) (Detail) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Feb. 27, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Public offering price	$ 19.25
Shares of PHI common stock	17,922,077
Underwriting discount	$ 0.67375
Initial pricing of equity forward instruments	$ 18.57625
Forward sale price		17.39
Proceeds from equity forward transaction	$ 312
Weighted-average price of shares	$ 19.93
Number of Shares	102,933
Value of stock outstanding	$ 2

XML

Commitments And Contingencies (Tax Legislation, Guarantees, Indemnifications, And Performance Contracts) (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	1 Months Ended
	Mar. 31, 2013
Commitment And Contingencies [Line Items]
Value of guarantees on both completed projects and projects under construction	$ 441
Value of guarantees under construction projects	15
Dividend declared on common stock, per share	$ 0.27
Energy Savings Or Combined Heat And Power Performance [Member]
Commitment And Contingencies [Line Items]
Accrued liability on contracts	$ 1
Pepco Energy Services [Member] | Energy Savings Or Combined Heat And Power Performance [Member]
Commitment And Contingencies [Line Items]
Contract life, maximum remaining term	20
Pepco Energy Services [Member] | Performance Contracts Associated With Savings Guarantees [Member]
Commitment And Contingencies [Line Items]
Contract life, maximum remaining term	13

XML

Related Party Transactions (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Potomac Electric Power Co [Member] | PHI Service Company [Member]
Costs directly charged or allocated	$ 55	$ 51
Potomac Electric Power Co [Member] | Pepco Energy Services [Member]
Maintenance services	8	5
Delmarva Power & Light Co/De [Member] | PHI Service Company [Member]
Costs directly charged or allocated	40	37
Atlantic City Electric Co [Member] | PHI Service Company [Member]
Costs directly charged or allocated	$ 31	$ 28

XML

Discontinued Operations (Schedule Of Cash Collateral Offset Against Derivative Positions) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Derivative [Line Items]
Cash collateral pledged to counterparties with the right to reclaim	$ 2	[1]	$ 6	[1]
Discontinued Operations [Member]
Derivative [Line Items]
Cash collateral pledged to counterparties with the right to reclaim	$ 8	[1]	$ 12	[1]

[1] Includes cash deposits on commodity brokerage accounts.

XML

Related Party Transactions (Schedule Of Related Party Transactions Included In Balance Sheet) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Potomac Electric Power Co [Member]
Related Party Transaction [Line Items]
(Payable to) Receivable from Related Party, Total	$ (49)		$ (41)
Potomac Electric Power Co [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
(Payable to) Receivable from Related Party, Total	(31)	[1]	(22)	[1]
Potomac Electric Power Co [Member] | Other [Member]
Related Party Transaction [Line Items]
(Payable to) Receivable from Related Party, Total	(1)	[2]	(1)	[2]
Potomac Electric Power Co [Member] | Pepco Energy Services [Member]
Related Party Transaction [Line Items]
(Payable to) Receivable from Related Party, Total	(17)	[2]	(18)	[2]
Delmarva Power & Light Co/De [Member]
Related Party Transaction [Line Items]
(Payable to) Receivable from Related Party, Total	(22)		(20)
Delmarva Power & Light Co/De [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
(Payable to) Receivable from Related Party, Total	(21)		(19)
Delmarva Power & Light Co/De [Member] | Other [Member]
Related Party Transaction [Line Items]
(Payable to) Receivable from Related Party, Total	(1)		(1)
Atlantic City Electric Co [Member]
Related Party Transaction [Line Items]
(Payable to) Receivable from Related Party, Total	(17)		(14)
Atlantic City Electric Co [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
(Payable to) Receivable from Related Party, Total	(16)	[1]	(13)	[1]
Atlantic City Electric Co [Member] | Other Related Party [Member]
Related Party Transaction [Line Items]
(Payable to) Receivable from Related Party, Total	$ (1)	[1]	$ (1)	[1]

[1] Included in Accounts Payable Due to Associated Companies.

[2] 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. Amount also includes charges for utility work performed by Pepco Energy Services on behalf of Pepco.

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Accumulated Other Comprehensive Loss (Schedule Of Components Of Other Comprehensive Loss) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance, beginning of period	$ (45)	$ (50)
Income Tax expense	(2)	(3)
Balance, end of period	(42)	(45)
Commodity Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance, beginning of period	(3)	(16)
Total net pre-tax loss reclassified into income	3	7
Income Tax expense	(1)	(2)
Net change during period	2	5
Balance, end of period	(1)	(11)
Commodity Derivatives [Member] | Fuel And Purchased Energy Expense [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total net pre-tax loss reclassified into income	3	7
Commodity Derivatives [Member] | Revenue [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total net pre-tax loss reclassified into income
Treasury Lock [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance, beginning of period	(10)	(10)
Total net pre-tax loss reclassified into income
Income Tax expense
Net change during period
Balance, end of period	(10)	(10)
Treasury Lock [Member] | Interest Expense [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total net pre-tax loss reclassified into income
Pension And Other Postretirement Benefit Plans [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance, beginning of period	(32)	(24)
Total net pre-tax loss reclassified into income	2	1
Income Tax expense	(1)	(1)
Net change during period	1
Balance, end of period	(31)	(24)
Pension And Other Postretirement Benefit Plans [Member] | Other Operation And Maintenance Expense [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total net pre-tax loss reclassified into income	$ 2	$ 1

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Fair Value Disclosures (Fair Value Of Financial Liabilities Measured On Recurring Basis) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	$ 5,194	[1]	$ 5,004	[2]
Transition Bonds issued by ACE Funding, Fair Value	327	[3]	341	[4]
Long-term project funding, Fair Value	13		13
Total Liabilities, Fair Value	5,534		5,358
Long-term debt, Carrying Amount	4,426		4,177
Transition Bonds issued by ACE Funding, Carrying Amount	285		295
Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	386	[1]	204	[2]
Total Liabilities, Fair Value	386		204
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	4,326	[1]	4,313	[2]
Transition Bonds issued by ACE Funding, Fair Value	327	[3]	341	[4]
Total Liabilities, Fair Value	4,653		4,654
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	482	[1]	487	[2]
Long-term project funding, Fair Value	13		13
Total Liabilities, Fair Value	495		500
Potomac Electric Power Co [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	2,387	[5]	2,160	[6]
Total Liabilities, Fair Value	2,387		2,160
Long-term debt, Carrying Amount	1,951		1,701
Potomac Electric Power Co [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	371	[5]	204	[6]
Total Liabilities, Fair Value	371		204
Potomac Electric Power Co [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	2,016	[5]	1,956	[6]
Total Liabilities, Fair Value	2,016		1,956
Delmarva Power & Light Co/De [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	968	[7]	990	[8]
Total Liabilities, Fair Value	968		990
Long-term debt, Carrying Amount	917		917
Delmarva Power & Light Co/De [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	15	[7]
Total Liabilities, Fair Value	15
Delmarva Power & Light Co/De [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	841	[7]	877	[8]
Total Liabilities, Fair Value	841		877
Delmarva Power & Light Co/De [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	112	[7]	113	[8]
Total Liabilities, Fair Value	112		113
Atlantic City Electric Co [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	1,007	[9]	1,016	[10]
Transition Bonds issued by ACE Funding, Fair Value	327	[3]	341	[4]
Total Liabilities, Fair Value	1,334		1,357
Long-term debt, Carrying Amount	829		829
Transition Bonds issued by ACE Funding, Carrying Amount	285		295
Atlantic City Electric Co [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value		[9]		[10]
Total Liabilities, Fair Value
Atlantic City Electric Co [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	877	[9]	884	[10]
Transition Bonds issued by ACE Funding, Fair Value	327	[3]	341	[4]
Total Liabilities, Fair Value	1,204		1,225
Atlantic City Electric Co [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	130	[9]	132	[10]
Total Liabilities, Fair Value	$ 130		$ 132

[1] The carrying amount for Long-term debt is $4,426 million as of March 31, 2013.

[2] The carrying amount for Long-term debt is $4,177 million as of December 31, 2012.

[3] The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $285 million as of March 31, 2013.

[4] The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $295 million as of December 31, 2012.

[5] The carrying amount for Long-term debt is $1,951 million as of March 31, 2013.

[6] The carrying amount for Long-term debt is $1,701 million as of December 31, 2012.

[7] The carrying amount for Long-term debt is $917 million as of March 31, 2013.

[8] The carrying amount for Long-term debt is $917 million as of December 31, 2012.

[9] The carrying amount for Long-term debt is $829 million as of March 31, 2013.

[10] The carrying amount for Long-term debt is $829 million as of December 31, 2012.

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Discontinued Operations

3 Months Ended

Mar. 31, 2013

Discontinued Operations And Disposal Groups [Abstract]

Discontinued Operations

(17) DISCONTINUED OPERATIONS

On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all of the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, gas inventory and derivative contracts. The transaction was completed on April 1, 2013. The agreement eliminated the retail natural gas supply business from the ongoing operations of Pepco Energy Services effective April 1, 2013 and Pepco Energy Services will not have significant continuing involvement in the retail natural gas supply business thereafter. As a result, PHI commenced reporting the results of operations of Pepco Energy Services’ retail natural gas supply business in discontinued operations in all periods presented in the accompanying consolidated statements of income. Further, certain assets and liabilities of Pepco Energy Services’ retail natural gas supply business are reported as held for sale as of each date presented in the accompanying consolidated balance sheets. Upon completion of the transaction, Pepco Energy Services received $8 million of collateral that it had pledged against its retail natural gas supply derivatives.

Operating Results

The operating results for the retail natural gas supply business of Pepco Energy Services are as follows:

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
Income from operations of discontinued operations, net of income taxes	$	2		$	5
Unrealized losses associated with retail natural gas supply contracts, net of income taxes		(2	)		—
Income From Discontinued Operations, Net of Income Taxes	$	—		$	5

Unrealized losses associated with retail natural gas supply contracts, net of income taxes includes unrealized derivative losses that were previously included in AOCL and were reclassified to income upon entering into the March 21, 2013 agreement, because PHI determined that the hedged forecasted purchases of supply for retail natural gas customers were probable not to occur. Accordingly, during the first quarter of 2013, PHI recognized $4 million of pre-tax unrealized derivative losses ($2 million after tax) that previously were included in AOCL as cash flow hedges. As a result of the completion of the transaction in the second quarter of 2013, PHI expects to record a pre-tax gain of approximately $8 million ($5 million after tax).

Balance Sheet Information

As March 31, 2013 and December 31, 2012, the retail natural gas supply business of Pepco Energy Services had inventory assets of less than $1 million and $1 million, respectively, and gross derivative liabilities of $8 million and $12 million, respectively, exclusive of the collateral pledged by Pepco Energy Services against the derivative liabilities. The fair value of the derivative liabilities were considered level 1 within the fair value hierarchy.

Derivative Instruments and Hedging Activities

Derivatives were used by the retail natural gas supply business of Pepco Energy Services to hedge commodity price risk.

The retail natural gas supply business of Pepco Energy Services entered into energy commodity contracts in the form of natural gas futures, swaps, options and forward contracts to hedge commodity price risk in connection with the purchase of physical natural gas for distribution to customers. The primary risk management objective was 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 became available.

Commodity contracts held by the retail natural gas supply business of Pepco Energy Services that were not designated for hedge accounting, did not qualify for hedge accounting, or did not meet the requirements for normal purchase and normal sale accounting, were marked to market through current earnings. Forward contracts that met the requirements for normal purchase and normal sale accounting were recorded on an accrual basis.

The tables below identify the balance sheet location and fair values of the retail natural gas supply business’ derivative instruments as of March 31, 2013 and December 31, 2012:

	As of March 31, 2013
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)	$	—		$	(7	)	$	(7	)	$	7	$	—
Derivative liabilities (non-current liabilities)		—			(1	)		(1	)		1		—
Net Derivative liability	$	—		$	(8	)	$	(8	)	$	8	$	—
	As of December 31, 2012
Balance Sheet Caption	Derivatives Designated as Hedging Instruments (a)			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative liabilities (current liabilities)	$	(5	)	$	(5	)	$	(10	)	$	10	$	—
Derivative liabilities (non-current liabilities)		(1	)		(1	)		(2	)		2		—
Net Derivative (liability) asset	$	(6	)	$	(6	)	$	(12	)	$	12	$	—

(a) Amounts included in Derivatives Designated as Hedging Instruments primarily consist of derivatives that were designated as cash flow hedges prior to Pepco Energy Services’ election to discontinue cash flow hedge accounting for these derivatives.

Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), the retail natural gas supply business of Pepco Energy Services 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. No derivative assets or liabilities were available to be offset under master netting arrangements as of March 31, 2013 and December 31, 2012. The amount of cash collateral that was offset against these derivative positions is as follows:

	March 31, 2013		December 31, 2012
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	8	$	12

(a) Includes cash deposits on commodity brokerage accounts.

As of March 31, 2013 and December 31, 2012, all cash collateral pledged by the retail gas business 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

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. The retail natural gas supply business of Pepco Energy Services had elected to no longer apply cash flow hedge accounting to its natural gas derivatives. Amounts included in AOCL for these cash flow hedges as of March 31, 2013 and 2012 represent net losses on derivatives prior to the election to discontinue cash flow hedge accounting less amounts reclassified into income as the hedged transactions occurred or because the hedged transactions were deemed probable not to occur. Gains or losses on these derivatives after the election to discontinue cash flow hedge accounting were recognized in income.

The cash flow hedge activity during the three months ended March 31, 2013 and 2012 is provided in the tables below:

	Three Months Ended March 31,
	2013		2012
	(millions of dollars)
Amount of net pre-tax loss arising during the period included in Accumulated Other Comprehensive Loss	$	—	$	—
Amount of net pre-tax loss reclassified into income:
Effective portion:
Income from Discontinued Operations, Net of Income Taxes		1		6
Ineffective portion: (a)
Income from Discontinued Operations, Net of Income Taxes		4		—
Total net pre-tax loss reclassified into Income from Discontinued Operations, Net of Income Taxes		5		6
Net pre-tax gain on commodity derivatives included in Accumulated Other Comprehensive Loss	$	5	$	6

(a) Included in the table above is a loss of $4 million for the three months ended March 31, 2013, which was reclassified from AOCL to Income from Discontinued Operations, Net of Income Taxes because the forecasted hedged transactions were deemed probable not to occur. For the three months ended March 31, 2012, no amounts were reclassified from AOCL to Income from Discontinued Operations, Net of Income Taxes because the forecasted hedged transactions were deemed probable not to occur.

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss

Cash flow hedges are marked to market on the balance sheet with corresponding adjustments to AOCL for effective cash flow hedges. As of March 31, 2013, all of the losses in AOCL that were associated with derivatives that the retail natural gas supply business of Pepco Energy Services had previously designated as cash flow hedges have been reclassified to income. The table below provides details regarding effective cash flow hedges included in the retail natural gas supply business of Pepco Energy Services’ balance sheets as of March 31, 2012. Although the retail natural gas supply business of Pepco Energy Services elected to no longer apply cash flow hedge accounting to its derivatives prior to March 31, 2012, gains or losses previously deferred in AOCL prior to the decision to discontinue cash flow hedge accounting remained in AOCL until the hedged forecasted transaction occurred unless it was deemed probable that the hedged forecasted transaction would not occur. The data in the following 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:

Contracts	As of March 31, 2012				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Energy commodity (a)	$	10	$	7		26 months
Total	$	10	$	7

(a) The unrealized derivative losses recorded in AOCL relate to forecasted physical natural gas purchases which are used to supply retail natural gas contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on the retail natural gas supply business of Pepco Energy Services’ balance sheet and the purchase cost is not recognized until the period of distribution.

Other Derivative Activity

The retail natural gas supply business of Pepco Energy Services held certain derivatives that were not in hedge accounting relationships and were not designated as normal purchases or normal sales. These derivatives were recorded at fair value on the balance sheet with the gain or loss for changes in fair value recorded through Income from Discontinued Operations, Net of Income Taxes.

For the three months ended March 31, 2013 and 2012, the amount of the derivative gain (loss) for the retail natural gas supply business of Pepco Energy Services recognized in Income from Discontinued Operations, Net of Income Taxes is provided in the table below:

	Three Months Ended March 31,
	2013			2012
	(millions of dollars)
Reclassification of mark-to-market to realized on settlement of contracts	$	2		$	8
Unrealized mark-to-market loss		(3	)		(6	)
Total net (loss) gain	$	(1	)	$	2

As of March 31, 2013 and December 31, 2012, the retail natural gas supply business of Pepco Energy Services had the following net outstanding commodity forward contract quantities and net position on derivatives that did not qualify for hedge accounting:

	March 31, 2013				December 31, 2012
Commodity	Quantity		Net Position		Quantity		Net Position
Natural gas (MMBtu)		2,047,500		Long		2,867,500		Long

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Leasing Activities (Net Investment In Leases By Published Credit Ratings) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Leases [Line Items]
Rated Entities	$ 869	[1]	$ 1,237	[1]
AA/Aa And Above [Member]
Leases [Line Items]
Rated Entities	537	[1]	766	[1]
A [Member]
Leases [Line Items]
Rated Entities	$ 332	[1]	$ 471	[1]

[1] Excludes the credit ratings associated with collateral posted by the lessees in these transactions.

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Segment Information (Segment Financial Information For Continuing Operations) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012		Dec. 31, 2012
Segment Reporting Information [Line Items]
Operating Revenue	$ 852		$ 1,242
Operating Expenses	1,088		1,111
Operating (Loss) Income	(236)		131
Interest Expense	67		65
Total Assets (excluding Assets Held For Sale)	15,655				15,788
Goodwill	1,407				1,407
Non-cash pre-tax charge	373
Depreciation and amortization	112		110
Interest expense on uncertain tax positions	16
Income tax benefit related to uncertain and effectively settled tax positions			10
Power Delivery [Member]
Segment Reporting Information [Line Items]
Operating Revenue	1,124		1,055
Operating Expenses	1,001	[1]	954	[2]
Operating (Loss) Income	123		101
Interest Expense	56		53
Other Income (Expenses)	6		8
Income Tax Expense (Benefit)	15	[3]	9	[4]
Net Income (Loss) from Continuing Operations	58		47
Total Assets (excluding Assets Held For Sale)	12,453		11,473
Construction Expenditures	282		280
Goodwill	1,400		1,400
Depreciation and amortization	104		99
Interest benefit	12
Intersegment [Member]
Segment Reporting Information [Line Items]
Operating Revenue	(1)		(4)
Operating Expenses	(1)		(6)
Interest Income	(3)		(5)
Interest Expense	(4)		(5)
Preferred Stock Dividends	(1)		(1)
Pepco Energy Services [Member]
Segment Reporting Information [Line Items]
Operating Revenue	97		178
Operating Expenses	94	[1]	169	[2]
Operating (Loss) Income	3		9
Interest Expense			1
Other Income (Expenses)	1
Income Tax Expense (Benefit)	1	[3]	3
Net Income (Loss) from Continuing Operations	3		5
Total Assets (excluding Assets Held For Sale)	368		583
Construction Expenditures	1		5
Depreciation and amortization	2		6
Other Non-Regulated [Member]
Segment Reporting Information [Line Items]
Operating Revenue	(368)	[5]	13
Operating Expenses			1	[2]
Operating (Loss) Income	(368)		12
Interest Income	1		1
Interest Expense	1		3
Other Income (Expenses)	1		1
Preferred Stock Dividends	1		1
Income Tax Expense (Benefit)	53	[3],[6]
Net Income (Loss) from Continuing Operations	(421)		10
Total Assets (excluding Assets Held For Sale)	882		1,487
Depreciation and amortization			1
Interest expense on uncertain tax positions	16
Non cash charges for tax consequences	64
Valuation allowance against deferred tax assets	101
Corporate And Other [Member]
Segment Reporting Information [Line Items]
Operating Revenue	(1)	[7]	(4)	[8]
Operating Expenses	(7)	[1],[7]	(13)	[2],[8]
Operating (Loss) Income	6	[7]	9	[8]
Interest Income	(1)	[7]	(1)	[8]
Interest Expense	10	[7]	8	[8]
Other Income (Expenses)			(1)	[8]
Preferred Stock Dividends	(1)	[7]	(1)	[8]
Income Tax Expense (Benefit)	66	[3],[7]	(1)	[8]
Net Income (Loss) from Continuing Operations	(70)	[7]	1	[8]
Total Assets (excluding Assets Held For Sale)	1,952	[7]	1,684	[8]
Construction Expenditures	13	[7]	6	[8]
Depreciation and amortization	6		4
Interest expense on uncertain tax positions	66
PHI Consolidated [Member]
Segment Reporting Information [Line Items]
Operating Revenue	852		1,242
Operating Expenses	1,088	[1]	1,111	[2]
Operating (Loss) Income	(236)		131
Interest Expense	67		65
Other Income (Expenses)	8		8
Income Tax Expense (Benefit)	135	[3]	11
Net Income (Loss) from Continuing Operations	(430)		63
Total Assets (excluding Assets Held For Sale)	15,655		15,227
Construction Expenditures	$ 296		$ 291

[1] Includes depreciation and amortization expense of $112 million, consisting of $104 million for Power Delivery, $2 million for Pepco Energy Services and $6 million for Corporate and Other.

[2] Includes depreciation and amortization expense of $110 million, consisting of $99 million for Power Delivery, $6 million for Pepco Energy Services, $1 million for Other Non-Regulated and $4 million for Corporate and Other.

[3] Includes after-tax interest associated with uncertain and effectively settled tax positions allocated to each member of the consolidated group, including a $12 million interest benefit for Power Delivery and interest expense of $16 million and $66 million for Other Non-Regulated and Corporate and Other, respectively

[4] Includes income tax benefits of $10 million related to uncertain and effectively settled tax positions, primarily due to the effective settlement with the Internal Revenue Service with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position at Pepco.

[5] Includes a non-cash pre-tax charge of $373 million to reduce the carrying value of the cross-border energy lease investments.

[6] Includes non-cash charges of $64 million primarily for the tax consequences associated with PHI's change in intent regarding foreign investment opportunities associated with the cross-border energy lease investments and $101 million representing the establishment of valuation allowances against certain deferred tax assets of PCI included in Other Non-Regulated.

[7] Total Assets in this column includes Pepco Holdings' goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. 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. Corporate and Other includes intercompany amounts of $(1) million for Operating Revenue, $(1) million for Operating Expenses, $(3) million for Interest Income, $(4) million for Interest Expense and $(1) million for Preferred Stock Dividends.

[8] Total Assets in this column includes Pepco Holdings' goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. 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. Corporate and Other includes intercompany amounts of $(4) million for Operating Revenue, $(6) million for Operating Expenses, $(5) million for Interest Income, $(5) million for Interest Expense and $(1) million for Preferred Stock Dividends.

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Commitments And Contingencies (Schedule Of Commitments And Obligations) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Commitments And Contingencies [Line Items]
Energy procurement obligations of Pepco Energy Services	$ 75	[1]
Guarantees associated with disposal of Conectiv Energy assets	13	[2]
Guaranteed lease residual values	18	[3]
Total	106
Derivative portfolio guarantee	13
Obligations under guarantee	55
Minimum [Member]
Commitments And Contingencies [Line Items]
Lease term range	1 to 4 years
Maximum [Member]
Commitments And Contingencies [Line Items]
Lease term range	3 to 8 years
PHI [Member]
Commitments And Contingencies [Line Items]
Energy procurement obligations of Pepco Energy Services	75	[1]
Guarantees associated with disposal of Conectiv Energy assets	13	[2]
Guaranteed lease residual values	2	[3]
Total	90
Obligations under guarantee	8
Potomac Electric Power Co [Member]
Commitments And Contingencies [Line Items]
Energy procurement obligations of Pepco Energy Services		[1]
Guarantees associated with disposal of Conectiv Energy assets		[2]
Guaranteed lease residual values	5	[3]
Total	5
Obligations under guarantee	15
Delmarva Power & Light Co/De [Member]
Commitments And Contingencies [Line Items]
Energy procurement obligations of Pepco Energy Services		[1]
Guarantees associated with disposal of Conectiv Energy assets		[2]
Guaranteed lease residual values	7	[3]
Total	7
Obligations under guarantee	19
Atlantic City Electric Co [Member]
Commitments And Contingencies [Line Items]
Energy procurement obligations of Pepco Energy Services		[1]
Guarantees associated with disposal of Conectiv Energy assets		[2]
Guaranteed lease residual values	4	[3]
Total	4
Obligations under guarantee	$ 13

[1] PHI has contractual commitments for performance and related payments of Pepco Energy Services to counterparties under routine energy sales and procurement obligations.

[2] Represents guarantees by PHI of Conectiv Energy's derivatives portfolio transferred in connection with the disposition of Conectiv Energy's wholesale business. 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.

[3] Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $55 million, $8 million of which is a guaranty by PHI, $15 million by Pepco, $19 million by DPL and $13 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

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Accumulated Other Comprehensive Loss (Tables)

3 Months Ended

Mar. 31, 2013

Equity [Abstract]

Schedule Of Components Of Other Comprehensive Loss

	Three Months Ended March 31,
	2013			2012
Balance, beginning of period	$	(45	)	$	(50	)
Commodity Derivatives
Balance, beginning of period		(3	)		(16	)
Amount of net pre-tax loss reclassified into income:
Fuel and Purchased Energy expense		3			7
Revenue		—			—
Total net pre-tax loss reclassified into income		3			7
Income Tax expense		(1	)		(2	)
Net change during period		2			5
Balance, end of period		(1	)		(11	)
Treasury Lock
Balance, beginning of period		(10	)		(10	)
Amount of net pre-tax loss reclassified into income:
Interest expense		—			—
Total net pre-tax loss reclassified into income		—			—
Income Tax expense		—			—
Net change during period		—			—
Balance, end of period		(10	)		(10	)
Pension and Other Postretirement Benefit Plans
Balance, beginning of period		(32	)		(24	)
Amount of net pre-tax loss reclassified into income:
Other Operation and Maintenance expense		2			1
Total net pre-tax loss reclassified into income		2			1
Income Tax expense		(1	)		(1	)
Net change during period		1			—
Balance, end of period		(31	)		(24	)
Balance, end of period	$	(42	)	$	(45	)

XML

Pension And Other Postretirement Benefits (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Pension contributions	$ 60	$ 200
Pension and other postretirement net periodic benefit cost	25	26
Potomac Electric Power Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contributions		85
Pension and other postretirement net periodic benefit cost	8	11
Delmarva Power & Light Co/De [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contributions	10	85
Pension and other postretirement net periodic benefit cost	4	6
Atlantic City Electric Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contributions	30	30
Pension and other postretirement net periodic benefit cost	5	6
Other Postretirement Benefits [Member] | PHI Service Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contributions	20
Other Postretirement Benefits [Member] | Potomac Electric Power Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contributions		85
Other Postretirement Benefits [Member] | Delmarva Power & Light Co/De [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contributions	10	85
Other Postretirement Benefits [Member] | Atlantic City Electric Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contributions	$ 30	$ 30

XML

Fair Value Disclosures (Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	$ 200		$ 113
Derivative instruments, liabilities	44		53
Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	1	[1],[2]
Derivative instruments, liabilities			4	[1],[3]
Capacity [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	8	[1],[4]	8	[1],[4]
Derivative instruments, liabilities	11	[1],[4]	11	[1],[4]
Treasury Fund [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash equivalents	112		27
Money Market Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	17		17
Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	62		60
Executive deferred compensation plan liabilities	29		28
Electricity [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets			1	[1],[5]
Derivative instruments, liabilities	4	[1],[5]	10	[1],[5]
Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	130	[6]	44	[7]
Level 1 [Member] | Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	1	[1],[2],[6]
Level 1 [Member] | Treasury Fund [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash equivalents	112	[6]	27	[7]
Level 1 [Member] | Money Market Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	17	[6]	17	[7]
Level 1 [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets				[7]
Level 1 [Member] | Electricity [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets				[1],[5],[7]
Derivative instruments, liabilities				[1],[5],[7]
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	43	[6]	43	[7]
Derivative instruments, liabilities	33	[6]	38	[7]
Significant Other Observable Inputs (Level 2) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	43	[6]	42	[7]
Executive deferred compensation plan liabilities	29	[6]	28	[7]
Significant Other Observable Inputs (Level 2) [Member] | Electricity [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets			1	[1],[5],[7]
Derivative instruments, liabilities	4	[1],[5],[6]	10	[1],[5],[7]
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	27		26
Derivative instruments, liabilities	11		15
Significant Unobservable Inputs (Level 3) [Member] | Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, liabilities			4	[1],[3]
Significant Unobservable Inputs (Level 3) [Member] | Capacity [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	8	[1],[4]	8	[1],[4]
Derivative instruments, liabilities	11	[1],[4]	11	[1],[4]
Significant Unobservable Inputs (Level 3) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	19		18
Significant Unobservable Inputs (Level 3) [Member] | Electricity [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets				[1],[5]
Derivative instruments, liabilities				[1],[5]
Potomac Electric Power Co [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	156		71
Derivative instruments, liabilities	8		9
Potomac Electric Power Co [Member] | Treasury Fund [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash equivalents	85
Potomac Electric Power Co [Member] | Money Market Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	14		15
Potomac Electric Power Co [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	57		56
Executive deferred compensation plan liabilities	8		9
Potomac Electric Power Co [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	99	[8]	15	[7]
Potomac Electric Power Co [Member] | Level 1 [Member] | Treasury Fund [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash equivalents	85	[8]
Potomac Electric Power Co [Member] | Level 1 [Member] | Money Market Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	14	[8]	15	[7]
Potomac Electric Power Co [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	39	[8]	38	[7]
Derivative instruments, liabilities	8	[8]	9	[7]
Potomac Electric Power Co [Member] | Significant Other Observable Inputs (Level 2) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	39	[8]	38	[7]
Executive deferred compensation plan liabilities	8	[8]	9	[7]
Potomac Electric Power Co [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	18		18
Potomac Electric Power Co [Member] | Significant Unobservable Inputs (Level 3) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	18		18
Delmarva Power & Light Co/De [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	4		3
Derivative instruments, liabilities	1		4
Delmarva Power & Light Co/De [Member] | Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	1	[2],[9]
Derivative instruments, liabilities			4	[10],[3]
Delmarva Power & Light Co/De [Member] | Money Market Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	2		2
Delmarva Power & Light Co/De [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	1		1
Executive deferred compensation plan liabilities	1
Delmarva Power & Light Co/De [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	3	[6]	2	[7]
Delmarva Power & Light Co/De [Member] | Level 1 [Member] | Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	1	[2],[6],[9]
Delmarva Power & Light Co/De [Member] | Level 1 [Member] | Money Market Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	2	[6]	2	[7]
Delmarva Power & Light Co/De [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, liabilities	1	[6]
Delmarva Power & Light Co/De [Member] | Significant Other Observable Inputs (Level 2) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan liabilities	1	[6]
Delmarva Power & Light Co/De [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	1		1
Derivative instruments, liabilities			4
Delmarva Power & Light Co/De [Member] | Significant Unobservable Inputs (Level 3) [Member] | Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, liabilities			4	[10],[3]
Delmarva Power & Light Co/De [Member] | Significant Unobservable Inputs (Level 3) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	1		1
Atlantic City Electric Co [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	34		35
Derivative instruments, liabilities	12		12
Atlantic City Electric Co [Member] | Capacity [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	8	[1],[4]	8	[1],[4]
Derivative instruments, liabilities	11	[1],[4]	11	[1],[4]
Atlantic City Electric Co [Member] | Treasury Fund [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash equivalents	26		27
Atlantic City Electric Co [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan liabilities	1		1
Atlantic City Electric Co [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	26	[6]	27	[7]
Atlantic City Electric Co [Member] | Level 1 [Member] | Treasury Fund [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash equivalents	26	[6]	27	[7]
Atlantic City Electric Co [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, liabilities	1	[6]	1	[7]
Atlantic City Electric Co [Member] | Significant Other Observable Inputs (Level 2) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan liabilities	1	[6]	1	[7]
Atlantic City Electric Co [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	8		8
Derivative instruments, liabilities	11		11
Atlantic City Electric Co [Member] | Significant Unobservable Inputs (Level 3) [Member] | Capacity [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	8	[1],[4]	8	[1],[4]
Derivative instruments, liabilities	$ 11	[1],[4]	$ 11	[1],[4]

[1] The fair value of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

[2] Represents natural gas swaps purchased by DPL as part of a natural gas hedging program approved by the DPSC.

[3] Represents natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

[4] Represents derivatives associated with ACE SOCAs.

[5] Represents wholesale electricity futures and swaps that are used mainly as part of Pepco Energy Services' retail electric supply business.

[6] There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.

[7] There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.

[8] There were no transfers of instruments between level 1 and level 2 valuation categories during the three months end March 31, 2013.

[9] The fair values of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.

[10] The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral.

XML

Derivative Instruments And Hedging Activities (Narrative) (Detail) (USD $) In Millions, unless otherwise specified			3 Months Ended			3 Months Ended				3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2012 Pepco Energy Services [Member]	Mar. 31, 2013 Pepco Energy Services [Member]	Dec. 31, 2012 Pepco Energy Services [Member]	Mar. 31, 2013 Pepco Energy Services [Member] Natural Gas Derivatives [Member]	Mar. 31, 2012 Pepco Energy Services [Member] Natural Gas Derivatives [Member]	Mar. 31, 2013 Delmarva Power & Light Co/De [Member]	Dec. 31, 2012 Delmarva Power & Light Co/De [Member]	Mar. 31, 2013 Atlantic City Electric Co [Member]	Dec. 31, 2012 Atlantic City Electric Co [Member]
Derivative losses included in AOCL						$ 2	$ 16
Credit risk derivative liabilities, at fair value	2	8						0	4
Credit risk derivative liabilities, at fair value net	2	8						0	4
Net settlement amount in the event of a downgrade below investment grade	24	40						0	2
Additional collateral that would have to be posted in the event of an investment downgrade	24	40						0	2
Cash plus borrowing capacity to meet future liquidity needs	975	861						635	477
Debt instrument unused borrowing capacity amount for subsidiary				340	384
Estimated percentage of New Jersey load										15.00%
Derivative assets (non-current assets)	8	8								8	8
Derivative assets (non-current liabilities)	11	11								11	11
Unrealized loss on derivatives			$ (4)							$ 0

XML

Leasing Activities (Cross-Border Energy Lease Investments) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Leases [Abstract]
Scheduled lease payments to PHI, net of non-recourse debt	$ 1,842	$ 1,852
Less: Unearned and deferred income	(973)	(615)
Investment in finance leases held in trust	869	1,237
Less: Deferred income tax liabilities	(95)	(756)
Net investment in finance leases held in trust	$ 774	$ 481

XML

Organization

3 Months Ended

Mar. 31, 2013

Organization

(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.

Each of PHI, Pepco, DPL and ACE is also a Reporting Company under the Securities Exchange Act of 1934, as amended. Together, Pepco, DPL and ACE constitute the Power Delivery segment, for financial reporting purposes.

Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy savings performance contracting services, high voltage underground transmission cabling, low voltage construction and maintenance services, and construction and operation of combined heat and power and central energy plants. Pepco Energy Services is in the process of winding down its competitive retail electric and natural gas 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 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

Each of Pepco, DPL and ACE is a regulated public utility 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 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 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.

Pepco Energy Services

Pepco Energy Services is engaged in the following businesses:

• providing energy savings performance contracting 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 underground transmission construction and maintenance services to customers throughout the United States, as well as low voltage electric construction and maintenance services and streetlight construction services to utilities, municipalities and other customers in the Washington, D.C. metropolitan area, and

• providing retail customers electricity under its remaining contractual obligations.

During 2012, Pepco Energy Services deactivated its Buzzard Point oil-fired generation facility and its Benning Road oil-fired generation facility. Pepco Energy Services has placed the facilities into an idle condition termed a “Cold Closure.” A Cold Closure requires that the utility service be disconnected so that the facilities are no longer operable and that the facilities require only essential maintenance until they are completely decommissioned.

In December 2009, PHI announced the wind-down of the retail electric and natural gas supply components of the Pepco Energy Services business. Pepco Energy Services is implementing this wind-down by not entering into any new retail electric supply contracts while continuing to perform under its existing electric supply contracts through their respective expiration dates, the last of which is June 1, 2014. Also, as discussed below, on March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all of the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, gas inventory and derivative contracts. The transaction was completed on April 1, 2013.

The retail electric 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 electric supply business for the three months ended March 31, 2013 and 2012 were $41 million and $108 million, respectively, while operating income for the same periods was $1 million and $6 million, respectively.

In connection with the operation of the retail electric supply business, Pepco Energy Services provided letters of credit of less than $1 million and posted net cash collateral of $5 million as of March 31, 2013. These collateral requirements, which are based on existing wholesale electricity 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 savings services business will not be affected by the wind-down of the retail electric supply business.

Other Business Operations

Other Non-Regulated is a separate operating segment for financial reporting purposes and includes the portfolio of cross-border energy lease investments held through PHI’s subsidiary, Potomac Capital Investment Corporation (PCI). For a discussion of the Other Non- Regulated segment, see Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust,” Note (11), “Income Taxes,” and Note (15), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments.”

Discontinued Operations

On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all of the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, gas inventory and derivative contracts. The transaction was completed on April 1, 2013. The operations of Pepco Energy Services’ retail natural gas supply business are being accounted for as a discontinued operation and are no longer a part of the Pepco Energy Services segment for financial reporting purposes. Substantially all of the information in these notes to the consolidated financial statements with respect to Pepco Energy Services’ retail natural gas supply business has been consolidated in Note (17), “Discontinued Operations.”

Potomac Electric Power Co [Member]

Organization

(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 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).

Delmarva Power & Light Co/De [Member]

Organization

(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 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).

Atlantic City Electric Co [Member]

Organization

(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).

XML

Derivative Instruments And Hedging Activities (Cash Flow Hedges Included In Accumulated Other Comprehensive Loss) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated Other Comprehensive Loss After-tax	$ 11		$ 21
Portion Expected to be Reclassified to Income during the Next 12 Months	2		11
Energy Commodity [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated Other Comprehensive Loss After-tax	1	[1]	11	[2]
Portion Expected to be Reclassified to Income during the Next 12 Months	1	[1]	10	[2]
Maximum Term	2 months	[1]	14 months	[2]
Interest Rate [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated Other Comprehensive Loss After-tax	10		10
Portion Expected to be Reclassified to Income during the Next 12 Months	$ 1		$ 1
Maximum Term	233 months		245 months

[1] The unrealized derivative losses recorded in AOCL relate to forecasted physical electricity purchases which are used to supply retail electricity contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on PHI's consolidated balance sheet for the retail contracts and the purchase cost is not recognized until the period of distribution.

[2] The unrealized derivative losses recorded in AOCL relate to forecasted physical and electricity purchases which are used to supply retail electricity contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on PHI's consolidated balance sheet for the retail contracts and the purchase cost is not recognized until the period of distribution.

XML

Goodwill (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Goodwill [Line Items]
Goodwill	$ 1,407	$ 1,407
Delmarva Power & Light Co/De [Member]
Goodwill [Line Items]
Goodwill	$ 8	$ 8

XML

Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2013

Regulated Operations [Abstract]

Schedule Of Current Base Rate Increase Requisition To Increase Annual Revenue

The following table shows, for each of the PHI utility subsidiaries, the current base rate cases filed. Please see the discussion below for more information concerning each of these filings.

Jurisdiction/Company	Current Requested Revenue Requirement Increase		Requested Return on Equity			Filing Date			Expected Timing of Decision
	(Millions of Dollars)
MD – Pepco Electric	$	60.8		10.25	%		11/30/12			Q3-2013
DE – DPL Gas		12.2		10.25	%		12/07/12			Q3-2013
NJ – ACE Electric		70.4		10.25	%		01/04/13	(a)		Q4-2013
DC – Pepco Electric		52.1		10.25	%		03/08/13			Q4-2013
DE – DPL Electric		42.0		10.25	%		03/22/13			Q4-2013
MD – DPL Electric		22.8		10.25	%		03/29/13			Q4-2013
Total	$	260.3

^(a) Filed 12/11/12; updated test period to 12 months actual data on 01/04/13.

XML

Segment Information (Tables)

3 Months Ended

Mar. 31, 2013

Segment Reporting [Abstract]

Segment Financial Information For Continuing Operations

Three Months Ended March 31, 2013
	(millions of dollars)
	Power Delivery		Pepco Energy Services		Other Non- Regulated			Corporate and Other  (a)			PHI Consolidated
Operating Revenue	$	1,124	$	97	$	(368	)(b)	$	(1	)	$	852
Operating Expenses (c)		1,001		94		—			(7	)		1,088
Operating Income (Loss)		123		3		(368	)		6			(236	)
Interest Income		—		—		1			(1	)		—
Interest Expense		56		—		1			10			67
Other Income		6		1		1			—			8
Preferred Stock Dividends		—		—		1			(1	)		—
Income Tax Expense (d)		15		1		53	(e)		66			135
Net Income (Loss) from Continuing Operations		58		3		(421	)		(70	)		(430	)
Total Assets (excluding Assets Held For Sale)		12,453		368		882			1,952			15,655
Construction Expenditures	$	282	$	1	$	—		$	13		$	296

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. 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. Corporate and Other includes intercompany amounts of $(1) million for Operating Revenue, $(1) million for Operating Expenses, $(3) million for Interest Income, $(4) million for Interest Expense and $(1) million for Preferred Stock Dividends.

(b) Includes a non-cash pre-tax charge of $373 million to reduce the carrying value of the cross-border energy lease investments.

(c) Includes depreciation and amortization expense of $112 million, consisting of $104 million for Power Delivery, $2 million for Pepco Energy Services and $6 million for Corporate and Other.

(d) Includes after-tax interest associated with uncertain and effectively settled tax positions allocated to each member of the consolidated group, including a $12 million interest benefit for Power Delivery and interest expense of $16 million and $66 million for Other Non-Regulated and Corporate and Other, respectively.

(e) Includes non-cash charges of $64 million primarily for the tax consequences associated with PHI’s change in intent regarding foreign investment opportunities associated with the cross-border energy lease investments and $101 million representing the establishment of valuation allowances against certain deferred tax assets of PCI included in Other Non-Regulated.

	Three Months Ended March 31, 2012
	(millions of dollars)
	Power Delivery			Pepco Energy Services		Other Non- Regulated		Corporate and Other  (a)			PHI Consolidated
Operating Revenue	$	1,055		$	178	$	13	$	(4	)	$	1,242
Operating Expenses (b)		954			169		1		(13	)		1,111
Operating Income		101			9		12		9			131
Interest Income		—			—		1		(1	)		—
Interest Expense		53			1		3		8			65
Other Income (Expenses)		8			—		1		(1	)		8
Preferred Stock Dividends		—			—		1		(1	)		—
Income Tax Expense (Benefit)		9	(c)		3		—		(1	)		11
Net Income from Continuing Operations		47			5		10		1			63
Total Assets (excluding Assets Held For Sale)		11,473			583		1,487		1,684			15,227
Construction Expenditures	$	280		$	5	$	—	$	6		$	291

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. 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. Corporate and Other includes intercompany amounts of $(4) million for Operating Revenue, $(6) million for Operating Expenses, $(5) million for Interest Income, $(5) million for Interest Expense and $(1) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization expense of $110 million, consisting of $99 million for Power Delivery, $6 million for Pepco Energy Services, $1 million for Other Non-Regulated and $4 million for Corporate and Other.

(c) Includes income tax benefits of $10 million related to uncertain and effectively settled tax positions, primarily due to the effective settlement with the Internal Revenue Service with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position at Pepco.

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Equity And Earnings Per Share (Schedule Of Basic And Diluted Earnings Per Share) (Detail) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Income Statement [Abstract]
Net (Loss) Income from continuing operations	$ (430)		$ 63
Net (Loss) Income from discontinued operations			5
Net (Loss) Income	$ (430)		$ 68
Average shares outstanding	237,000,000		228,000,000
Adjustment to shares outstanding
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock	237,000,000		228,000,000
Net effect of potentially dilutive shares		[1]		[1]
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock	237,000,000		228,000,000
Earnings per share of common stock from continuing operations	$ (1.82)		$ 0.28
Earnings per share of common stock from discontinued operations			$ 0.02
Basic and diluted (loss) earnings per share	$ (1.82)		$ 0.30
Number of options excluded from diluted EPS calculation	0		3,000

[1] The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS as they are considered to be anti-dilutive were zero and 3,000 for the three months ended March 31, 2013 and 2012, respectively.

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Regulatory Matters (Schedule Of Current Base Rate Increase Requisition To Increase Annual Revenue) (Detail) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended	1 Months Ended			3 Months Ended	12 Months Ended	3 Months Ended					1 Months Ended	3 Months Ended
	Mar. 29, 2013	Mar. 31, 2013	Mar. 08, 2013 Potomac Electric Power Co [Member]	Nov. 30, 2012 Potomac Electric Power Co [Member]	Jul. 31, 2012 Potomac Electric Power Co [Member]	Mar. 31, 2013 Potomac Electric Power Co [Member]	Dec. 31, 2011 Potomac Electric Power Co [Member]	Mar. 31, 2013 Potomac Electric Power Co [Member] MD [Member]	Mar. 31, 2013 Potomac Electric Power Co [Member] DC [Member]	Mar. 31, 2013 Delmarva Power Light Co Gas [Member] DE [Member]	Mar. 31, 2013 Delmarva Power Light Co Electric [Member] MD [Member]	Mar. 31, 2013 Delmarva Power Light Co Electric [Member] DE [Member]	Dec. 31, 2012 Atlantic City Electric Co [Member]	Mar. 31, 2013 Atlantic City Electric Co [Member]	Mar. 31, 2013 Atlantic City Electric Co [Member] NJ [Member]
Regulatory Matters [Line Items]
Requested rate change	$ 22.8	$ 260.3	$ 52.1	$ 60.8	$ 18.1			$ 60.8	$ 52.1	$ 12.2	$ 22.8	$ 42.0			$ 70.4
Return on equity, percentage	10.25%		10.25%	10.25%	9.31%	10.80%	10.75%	10.25%	10.25%	10.25%	10.25%	10.25%	10.25%	10.80%	10.25%
Initial Filing Date								Nov. 30, 2012	Mar. 08, 2013	Dec. 07, 2012	Mar. 29, 2013	Mar. 22, 2013			Jan. 04, 2013	[1]
Expected Timing of Decision								Q3-2013	Q4-2013	Q3-2013	Q4-2013	Q4-2013			Q4-2013

[1] Filed 12/11/12; updated test period to 12 months actual data on 01/04/13.

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Leasing Activities (Tables)

3 Months Ended

Mar. 31, 2013

Leases [Abstract]

Cross-Border Energy Lease Investments

	March 31, 2013			December 31, 2012
	(millions of dollars)
Scheduled lease payments to PHI, net of non-recourse debt	$	1,842		$	1,852
Less: Unearned and deferred income		(973	)		(615	)
Investment in finance leases held in trust		869			1,237
Less: Deferred income tax liabilities		(95	)		(756	)
Net investment in finance leases held in trust	$	774		$	481

Income Recognized From Cross-Border Energy Lease Investments

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
Pre-tax income from PHI’s cross-border energy lease investments (included in Other Revenue)	$	5		$	13
Non-cash charge to reduce carrying value of PHI’s cross-border energy lease investments		(373	)		—
Pre-tax (loss) income from PHI’s cross-border energy lease investments after adjustment		(368	)		13
Income tax (benefit) expense related to PHI’s cross-border energy lease investments, including interest expense on uncertain tax positions of $16 million		(48	)		1
Net (loss) income from PHI’s cross-border energy lease investments	$	(320	)	$	12

Net Investment In Leases By Published Credit Ratings

Lessee Rating (a)	March 31, 2013		December 31, 2012
	(millions of dollars)
Rated Entities
AA/Aa and above	$	537	$	766
A		332		471
Total	$	869	$	1,237

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

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Pension And Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2013

Compensation And Retirement Disclosure [Abstract]

Components Of Net Periodic Benefit Cost

	Pension Benefits						Other Postretirement Benefits
	2013			2012			2013			2012
	(millions of dollars)
Service cost	$	13		$	11		$	2		$	1
Interest cost		25			26			8			9
Expected return on plan assets		(37	)		(34	)		(5	)		(5	)
Amortization of prior service cost		—			—			(1	)		(1	)
Amortization of net actuarial loss		16			14			4			5
Net periodic benefit cost	$	17		$	17		$	8		$	9

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Consolidated Statement Of Equity (Parenthetical) (USD $)	3 Months Ended
	Mar. 31, 2013
Statement Of Stockholders Equity [Abstract]
Dividends on common stock, per share	$ 0.27

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2013

Reconciliation Of Effective Income Tax Rate From Continuing Operations

	Three Months Ended March 31,
	2013					2012
	(millions of dollars)
Income tax at Federal statutory rate	$	(103	)	35.0	%	$	26		35.0	%
Increases (decreases) resulting from:
State income taxes, net of Federal effect		5		(1.7	)%		4		5.4	%
Asset removal costs		(3	)	1.0	%		(3	)	(4.1	)%
Changes in estimates and interest related to uncertain and effectively settled tax positions		67		(22.7	)%		(13	)	(17.6	)%
Cross-border energy lease investments		64		(21.7	)%		(1	)	(1.4	)%
Establishment of valuation allowances related to deferred tax assets		101		(34.2	)%		—		—
Other, net		4		(1.5	)%		(2	)	(2.4	)%
Consolidated income tax expense related to continuing operations	$	135		(45.8	)%	$	11		14.9	%

Delmarva Power & Light Co/De [Member]

Reconciliation Of Effective Income Tax Rate From Continuing Operations

	Three Months Ended March 31,
	2013					2012
	(millions of dollars)
Income tax at Federal statutory rate	$	15		35.0	%	$	12	35.0	%
Increases (decreases) resulting from:
State income taxes, net of Federal effect		2		4.7	%		2	5.7	%
Changes in estimates and interest related to uncertain and effectively settled tax positions		(1	)	(2.4	)%		—	—
Other, net		—		0.8	%		—	(0.7	)%
Income tax expense	$	16		38.1	%	$	14	40.0	%

Potomac Electric Power Co [Member]

Reconciliation Of Effective Income Tax Rate From Continuing Operations

	Three Months Ended March 31,
	2013					2012
	(millions of dollars)
Income tax at Federal statutory rate	$	9		35.0	%	$	7		35.0	%
Increases (decreases) resulting from:
State income taxes, net of Federal effect		2		8.0	%		1		6.3	%
Asset removal costs		(3	)	(12.0	)%		(3	)	(15.8	)%
Changes in estimates and interest related to uncertain and effectively settled tax positions		(5	)	(20.0	)%		(10	)	(50.5	)%
Other, net		(1	)	(3.0	)%		—		(1.3	)%
Income tax expense (benefit)	$	2		8.0	%	$	(5	)	(26.3	)%

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Discontinued Operations (Cash Flow Hedges Included In Accumulated Other Comprehensive Loss) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated Other Comprehensive Loss After-tax	$ 11		$ 21
Portion Expected to be Reclassified to Income during the Next 12 Months	2		11
Energy Commodity [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated Other Comprehensive Loss After-tax	1	[1]	11	[2]
Portion Expected to be Reclassified to Income during the Next 12 Months	1	[1]	10	[2]
Maximum Term	2 months	[1]	14 months	[2]
Discontinued Operations [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated Other Comprehensive Loss After-tax			10
Portion Expected to be Reclassified to Income during the Next 12 Months			7
Discontinued Operations [Member] | Energy Commodity [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated Other Comprehensive Loss After-tax			10	[3]
Portion Expected to be Reclassified to Income during the Next 12 Months			$ 7	[3]
Maximum Term			26 months	[3]

[1] The unrealized derivative losses recorded in AOCL relate to forecasted physical electricity purchases which are used to supply retail electricity contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on PHI's consolidated balance sheet for the retail contracts and the purchase cost is not recognized until the period of distribution.

[2] The unrealized derivative losses recorded in AOCL relate to forecasted physical and electricity purchases which are used to supply retail electricity contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on PHI's consolidated balance sheet for the retail contracts and the purchase cost is not recognized until the period of distribution.

[3] The unrealized derivative losses recorded in AOCL relate to forecasted physical natural gas purchases which are used to supply retail natural gas contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on the retail natural gas supply business of Pepco Energy Services' balance sheet and the purchase cost is not recognized until the period of distribution.

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Organization (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Organization [Line Items]
Operating income	$ (236)	$ 131
Subsidiary Of Common Parent [Member] | Pepco Energy Services [Member]
Organization [Line Items]
Operating revenues	41	108
Operating income	1	6
Posted net cash collateral	5
Subsidiary Of Common Parent [Member] | Pepco Energy Services [Member] | Maximum [Member]
Organization [Line Items]
Letters of credit	$ 1

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Debt (Detail) (USD $)	3 Months Ended		1 Months Ended				1 Months Ended	3 Months Ended				3 Months Ended				3 Months Ended				1 Months Ended				3 Months Ended
	Mar. 31, 2013 D	Dec. 31, 2012	Mar. 28, 2013 Term Loan Agreement [Member]	Mar. 31, 2013 Term Loan Agreement [Member]	Mar. 28, 2013 In Addition To Federal Funds Rate [Member]	Mar. 28, 2013 Eurodollar Rate [Member]	Mar. 31, 2013 First Mortgage Bonds [Member]	Mar. 31, 2012 Maximum [Member]	Mar. 31, 2013 Maximum [Member] Term Loan Agreement [Member]	Mar. 31, 2013 Potomac Electric Power Co [Member] D	Dec. 31, 2012 Potomac Electric Power Co [Member]	Mar. 31, 2013 Potomac Electric Power Co [Member] First Mortgage Bonds [Member]	Mar. 31, 2012 Potomac Electric Power Co [Member] Maximum [Member]	Mar. 31, 2013 Delmarva Power & Light Co/De [Member] D	Dec. 31, 2012 Delmarva Power & Light Co/De [Member]	Mar. 31, 2012 Delmarva Power & Light Co/De [Member] Maximum [Member]	Mar. 31, 2013 Atlantic City Electric Co [Member] D	Dec. 31, 2012 Atlantic City Electric Co [Member]	Apr. 30, 2013 Atlantic City Electric Co [Member] Subsequent Event [Member]	Jan. 31, 2013 Atlantic City Electric Co [Member] Series 2002-1 Bonds, Class A-3 [Member]	Apr. 30, 2013 Atlantic City Electric Co [Member] Series 2002-1 Bonds, Class A-3 [Member] Subsequent Event [Member]	Jan. 31, 2013 Atlantic City Electric Co [Member] Series 2003-1 Bonds, Class A-2 [Member]	Apr. 30, 2013 Atlantic City Electric Co [Member] Series 2003-1 Bonds, Class A-2 [Member] Subsequent Event [Member]	Mar. 31, 2012 Atlantic City Electric Co [Member] Maximum [Member]	Mar. 31, 2013 Pepco Energy Services [Member]	Dec. 31, 2012 Pepco Energy Services [Member]	Mar. 31, 2013 Pepco Energy Services [Member] Maximum [Member] Retail Electric Supply Business [Member]	Dec. 31, 2012 Pepco Energy Services [Member] Maximum [Member] Retail Electric Supply Business [Member]
Debt Instrument [Line Items]
Line of credit facility, expiration date	Aug. 01, 2016									Aug. 01, 2016				Aug. 01, 2016			Aug. 01, 2016
Line of credit facility, extended expiration date	2017-08-01									2017-08-01				2017-08-01			2017-08-01
Line of credit facility maximum borrowing capacity	$ 1,500,000,000
Parent company credit facility letter of credit, maximum	500,000,000
Same day borrowings maximum percentage amount	10.00%									10.00%				10.00%			10.00%
Credit facility borrowing capacity	750,000,000									250,000,000				250,000,000			250,000,000
Maximum amount of credit available to parent	1,250,000,000
Subsidiary borrowing limit under parent's credit facility	500,000,000									500,000,000				500,000,000			500,000,000
Debt instrument variable interest rate in addition to the federal funds effective rate	0.50%									0.50%				0.50%			0.50%
Debt instrument variable interest rate in addition to one month LIBOR's effective rate	1.00%									1.00%				1.00%			1.00%
Ratio of indebtedness to total capitalization								65.00%	65.00%				65.00%			65.00%								65.00%
Ratio of deferrable interest subordinated debt to total capitalization								15.00%	15.00%				15.00%			15.00%								15.00%
Borrowing capacity under the credit facility	975,000,000	861,000,000								635,000,000	477,000,000			635,000,000	477,000,000		635,000,000	477,000,000
Utility subsidiaries combined cash and borrowing capacity	635,000,000	477,000,000
Ongoing commercial paper	875,000,000									500,000,000				500,000,000			250,000,000
Commercial paper outstanding	408,000,000									0				70,000,000			185,000,000
Commercial paper weighted average interest rate	0.76%									0.38%				0.36%			0.37%
Commercial paper weighted average maturity, in days	10									7				3			7
Carrying value of instrument		200,000,000	250,000,000				250,000,000					250,000,000							4,400,000
Margin added to stated rate			0.875%		0.50%	1.00%
Debt instrument, interest percentage				1.09%			4.15%					4.15%
Debt instrument maturity date			Mar. 27, 2014				Mar. 15, 2043					Mar. 15, 2043
Debt instrument principal payment																				7,000,000	7,000,000	3,000,000	3,000,000
Cash collateral posted																									5,000,000	14,000,000
Letters of credit posted																											1,000,000	1,000,000
Borrowing capacity under PHI's credit facility																									$ 340,000,000	$ 384,000,000

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Commitments And Contingencies (Retained Environmental Exposures) (Detail) (USD $) In Millions, unless otherwise specified	1 Months Ended			12 Months Ended
	Jul. 31, 2010	Jul. 31, 2010 Conectiv Energy [Member]	Jul. 31, 2010 PHI [Member]	Dec. 31, 2012 Pepco Energy Services [Member]
Commitment And Contingencies [Line Items]
Certain allegedly unauthorized charges				$ 7
Additional compounded interest				9
Environmental remediation expense minimum	7
Environmental remediation expense maximum	18
Third party maximum and seller floor for environmental remediation costs		$ 10	$ 10

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Consolidated Statements Of (Loss) Income (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Operating Revenue
Power Delivery	$ 1,124	$ 1,055
Pepco Energy Services	97	178
Other	(369)	9
Total Operating Revenue	852	1,242
Operating Expenses
Fuel and purchased energy	600	641
Other services cost of sales	40	47
Other operation and maintenance	230	224
Depreciation and amortization	112	110
Other taxes	105	104
Deferred electric service costs	1	(15)
Total Operating Expenses	1,088	1,111
Operating (Loss) Income	(236)	131
Other Income (Expenses)
Interest expense	(67)	(65)
Other income	8	8
Total Other Expenses	(59)	(57)
(Loss) Income from Continuing Operations Before Income Tax Expense (Benefit)	(295)	74
Income Tax Expense Related to Continuing Operations	135	11
Net (Loss) Income from Continuing Operations	(430)	63
Income from Discontinued Operations, Net of Income Taxes		5
Net (Loss) Income	(430)	68
Basic and Diluted Earnings per Share Information
Weighted average shares outstanding - Basic	237	228
Weighted average shares outstanding - Diluted	237	228
(Loss) earnings per share of common stock from Continuing Operations - Basic and Diluted	$ (1.82)	$ 0.28
Earnings per share of common stock from Discontinued Operations - Basic and Diluted		$ 0.02
Basic and Diluted (loss) earnings per share	$ (1.82)	$ 0.30
Potomac Electric Power Co [Member]
Operating Revenue
Total Operating Revenue	477	465
Operating Expenses
Purchased energy	192	185
Other operation and maintenance	102	103
Depreciation and amortization	47	47
Other taxes	89	90
Total Operating Expenses	430	425
Operating (Loss) Income	47	40
Other Income (Expenses)
Interest expense	(26)	(25)
Other income	4	4
Total Other Expenses	(22)	(21)
(Loss) Income from Continuing Operations Before Income Tax Expense (Benefit)	25	19
Income Tax Expense Related to Continuing Operations	2	(5)
Income Tax Expense (Benefit)	2	(5)
Net (Loss) Income	23	24
Delmarva Power & Light Co/De [Member]
Operating Revenue
Electric	285	259
Natural gas	85	74
Total Operating Revenue	370	333
Operating Expenses
Purchased energy	159	143
Gas purchased	54	49
Other operation and maintenance	69	65
Depreciation and amortization	25	24
Other taxes	10	9
Total Operating Expenses	317	290
Operating (Loss) Income	53	43
Other Income (Expenses)
Interest expense	(13)	(11)
Other income	2	3
Total Other Expenses	(11)	(8)
(Loss) Income from Continuing Operations Before Income Tax Expense (Benefit)	42	35
Income Tax Expense Related to Continuing Operations	16	14
Income Tax Expense (Benefit)	16	14
Net (Loss) Income	26	21
Atlantic City Electric Co [Member]
Operating Revenue
Total Operating Revenue	277	256
Operating Expenses
Purchased energy	157	166
Other operation and maintenance	61	56
Depreciation and amortization	31	28
Other taxes	4	4
Deferred electric service costs	1	(15)
Total Operating Expenses	254	239
Operating (Loss) Income	23	17
Other Income (Expenses)
Interest expense	(17)	(17)
Other income		1
Total Other Expenses	(17)	(16)
(Loss) Income from Continuing Operations Before Income Tax Expense (Benefit)	6	1
Income Tax Expense (Benefit)	(3)	(1)
Net (Loss) Income	$ 9	$ 2

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Regulatory Matters (Narrative) (Detail) (USD $)	1 Months Ended				3 Months Ended		1 Months Ended				1 Months Ended					3 Months Ended	12 Months Ended				1 Months Ended			3 Months Ended	12 Months Ended		1 Months Ended	3 Months Ended	1 Months Ended		1 Months Ended			1 Months Ended			1 Months Ended										3 Months Ended	12 Months Ended		0 Months Ended	1 Months Ended	3 Months Ended	1 Months Ended	3 Months Ended	1 Months Ended		3 Months Ended	1 Months Ended			1 Months Ended				3 Months Ended		1 Months Ended			3 Months Ended	1 Months Ended
	Mar. 29, 2013	Mar. 31, 2013	Dec. 31, 2012	Aug. 31, 2012	Mar. 31, 2013	Apr. 30, 2012 MW	Sep. 30, 2012 Expected [Member]	Mar. 31, 2013 Phi [Member]	Apr. 30, 2012 Maximum [Member] MW	Apr. 30, 2012 Minimum [Member] MW	Mar. 08, 2013 Potomac Electric Power Co [Member]	Dec. 31, 2012 Potomac Electric Power Co [Member]	Nov. 30, 2012 Potomac Electric Power Co [Member]	Jul. 31, 2012 Potomac Electric Power Co [Member]	Nov. 01, 2008 Potomac Electric Power Co [Member]	Mar. 31, 2013 Potomac Electric Power Co [Member]	Dec. 31, 2012 Potomac Electric Power Co [Member]	Dec. 31, 2011 Potomac Electric Power Co [Member]	Feb. 28, 2013 Potomac Electric Power Co [Member]	Apr. 30, 2012 Potomac Electric Power Co [Member] MW	Nov. 01, 2008 Potomac Electric Power Co [Member] Non Recoverable Rate [Member]	Nov. 30, 2012 Potomac Electric Power Co [Member] Expected [Member]	Jul. 31, 2012 Potomac Electric Power Co [Member] Expected [Member]	Mar. 31, 2013 Potomac Electric Power Co [Member] Expected [Member]	Dec. 31, 2011 Potomac Electric Power Co [Member] Expected [Member]	Dec. 31, 2011 Potomac Electric Power Co [Member] Actual [Member]	Feb. 27, 2013 Potomac Electric Power Co [Member] Federal Energy Regulatory Commission Return On Equity Complaint [Member]	Mar. 31, 2013 Potomac Electric Power Co [Member] Federal Energy Regulatory Commission Return On Equity Complaint [Member]	Nov. 01, 2008 Potomac Electric Power Co [Member] Phi [Member]	Mar. 31, 2013 Potomac Electric Power Co [Member] Phi [Member]	Feb. 28, 2013 Potomac Electric Power Co [Member] Maximum [Member]	Apr. 30, 2012 Potomac Electric Power Co [Member] Maximum [Member] MW	Mar. 31, 2013 Potomac Electric Power Co [Member] Maximum [Member] Expected [Member]	Feb. 27, 2013 Potomac Electric Power Co [Member] Maximum [Member] Federal Energy Regulatory Commission Return On Equity Complaint [Member]	Feb. 28, 2013 Potomac Electric Power Co [Member] Minimum [Member]	Apr. 30, 2012 Potomac Electric Power Co [Member] Minimum [Member] MW	Feb. 27, 2013 Potomac Electric Power Co [Member] Minimum [Member] Federal Energy Regulatory Commission Return On Equity Complaint [Member]	Mar. 29, 2013 Delmarva Power & Light Co/De [Member]	Mar. 31, 2013 Delmarva Power & Light Co/De [Member]	Feb. 28, 2013 Delmarva Power & Light Co/De [Member]	Feb. 05, 2013 Delmarva Power & Light Co/De [Member]	Dec. 31, 2012 Delmarva Power & Light Co/De [Member]	Nov. 30, 2012 Delmarva Power & Light Co/De [Member]	Aug. 31, 2012 Delmarva Power & Light Co/De [Member]	Dec. 31, 2011 Delmarva Power & Light Co/De [Member]	Nov. 01, 2008 Delmarva Power & Light Co/De [Member]	Mar. 31, 2013 Delmarva Power & Light Co/De [Member]	Dec. 31, 2012 Delmarva Power & Light Co/De [Member]	Apr. 30, 2012 Delmarva Power & Light Co/De [Member] MW	Jun. 01, 2013 Delmarva Power & Light Co/De [Member] Subsequent Event [Member]	Jun. 01, 2013 Delmarva Power & Light Co/De [Member] Subsequent Event [Member]	Mar. 31, 2013 Delmarva Power & Light Co/De [Member] Expected [Member]	Feb. 27, 2013 Delmarva Power & Light Co/De [Member] Federal Energy Regulatory Commission Return On Equity Complaint [Member]	Mar. 31, 2013 Delmarva Power & Light Co/De [Member] Federal Energy Regulatory Commission Return On Equity Complaint [Member]	Feb. 28, 2013 Delmarva Power & Light Co/De [Member] Maximum [Member]	Apr. 30, 2012 Delmarva Power & Light Co/De [Member] Maximum [Member] MW	Mar. 31, 2013 Delmarva Power & Light Co/De [Member] Maximum [Member] Expected [Member]	Feb. 27, 2013 Delmarva Power & Light Co/De [Member] Maximum [Member] Federal Energy Regulatory Commission Return On Equity Complaint [Member]	Feb. 28, 2013 Delmarva Power & Light Co/De [Member] Minimum [Member]	Apr. 30, 2012 Delmarva Power & Light Co/De [Member] Minimum [Member] MW	Feb. 27, 2013 Delmarva Power & Light Co/De [Member] Minimum [Member] Federal Energy Regulatory Commission Return On Equity Complaint [Member]	Mar. 31, 2013 Atlantic City Electric Co [Member]	Dec. 31, 2012 Atlantic City Electric Co [Member]	Feb. 28, 2012 Atlantic City Electric Co [Member]	Mar. 31, 2013 Atlantic City Electric Co [Member]	Jun. 30, 2012 Atlantic City Electric Co [Member]	Dec. 31, 2012 Atlantic City Electric Co [Member] Distribution Rate [Member]	Dec. 31, 2012 Atlantic City Electric Co [Member] Recovery Charges [Member]	Feb. 27, 2013 Atlantic City Electric Co [Member] Federal Energy Regulatory Commission Return On Equity Complaint [Member]	Mar. 31, 2013 Atlantic City Electric Co [Member] Federal Energy Regulatory Commission Return On Equity Complaint [Member]	Feb. 27, 2013 Atlantic City Electric Co [Member] Maximum [Member] Federal Energy Regulatory Commission Return On Equity Complaint [Member]	Feb. 27, 2013 Atlantic City Electric Co [Member] Minimum [Member] Federal Energy Regulatory Commission Return On Equity Complaint [Member]
Regulatory Matters [Line Items]
Effect of proposed change on gas cost rate				22.30%																																								22.30%
Requested rate change	$ 22,800,000				$ 260,300,000						$ 52,100,000		$ 60,800,000	$ 18,100,000								$ 60,800,000	$ 18,100,000		$ 68,400,000	$ 66,200,000												$ 22,800,000	$ 42,000,000			$ 12,200,000			$ 31,800,000
Return on equity, percentage	10.25%										10.25%		10.25%	9.31%		10.80%		10.75%									8.70%	11.30%			12.80%			10.33%	10.80%		6.78%	10.25%	10.25%			10.25%	9.75%		10.75%		10.80%						8.70%	11.30%	12.80%			10.33%	10.80%		6.78%		10.25%		10.80%				8.70%	11.30%	10.33%	6.78%
Contingent rate increase																																											22,000,000		24,800,000
Rate increase implemented																																								2,500,000	2,500,000		22,000,000		24,800,000					2,500,000	2,500,000
Surcharge for recovery of costs							10,200,000																	192,000,000																												10,200,000
Proposed incentive for meeting enhanced reliability goals																								1,000,000																												500,000					500,000
Credit to customers																																	1,000,000																								500,000
Requested rate change, net																																																															70,400,000				72,100,000	1,700,000
Projected deferred under-recovered balance related to non-utility generators																																																																113,800,000		127,000,000
Overall annual rate increase of the projected deferred under-recovered balance related to non-utility generators																																																														52,200,000		55,300,000	52,200,000
New power plant output						661			700	650										661												700				650													661							700				650
Capital expenditure			102,000,000														64,000,000																															38,000,000
Recovery			88,000,000
Basis point																50.00%			200.00%																				50.00%	200.00%							50.00%															50.00%			50.00%
Denied recovery amount		2,000,000													1,000,000	1,000,000													2,000,000																	1,000,000	1,000,000
Recovery percentage																50.00%					50.00%																									50.00%
Capital expenditure placed in service			11,000,000									11,000,000
Transfer of materials to inventory			3,000,000					2,000,000				3,000,000					3,000,000													2,000,000
Capital expenditure reclassified to regulatory asset			88,000,000									50,000,000					50,000,000																									38,000,000						38,000,000
Regulatory asset		84,000,000			84,000,000											47,000,000																							37,000,000								37,000,000
Amount sought to be recovered																	$ 50,000,000

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Consolidated Statements Of Cash Flows (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
OPERATING ACTIVITIES
Net (Loss) Income	$ (430)	$ 68
Income from discontinued operations		(5)
Adjustments to reconcile net (loss) income to net cash from operating activities:
Depreciation and amortization	112	110
Non-cash rents from cross-border energy lease investments	(5)	(13)
Non-cash charge to reduce carrying value of PHI's cross-border energy lease investments	373
Deferred income taxes	(496)	259
Other	(3)	(5)
Changes in:
Accounts receivable	(3)	78
Inventories	3
Prepaid expenses	10	8
Regulatory assets and liabilities, net	(6)	(37)
Accounts payable and accrued liabilities	(63)	(60)
Pension contributions	(60)	(200)
Pension benefit obligation, excluding contributions	14	15
Cash collateral related to derivative activities	17	20
Income tax-related prepayments, receivables and payables	604	(247)
Deposit made to taxing authority	(242)
Interest accrued	37	33
Other assets and liabilities	(5)	(2)
Net assets held for sale	(3)	1
Net Cash (Used By) From Operating Activities	(146)	23
INVESTING ACTIVITIES
Investment in property, plant and equipment	(296)	(291)
Department of Energy capital reimbursement awards received	1	7
Changes in restricted cash equivalents	2	1
Net other investing activities	(3)	2
Net Cash Used By Investing Activities	(296)	(281)
FINANCING ACTIVITIES
Dividends paid on common stock	(67)	(61)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation	15	17
Issuances of common stock	324
Issuances of long-term debt	250
Reacquisitions of long-term debt	(10)	(9)
Issuances of short-term debt, net	26	253
Issuance of term loan	250
Repayment of term loan	(200)
Cost of issuances	(16)	(3)
Net other financing activities	(30)	16
Net Cash From (Used By) Financing Activities	542	213
Net Increase (Decrease) in Cash and Cash Equivalents	100	(45)
Cash and Cash Equivalents at Beginning of Period	25	109
CASH AND CASH EQUIVALENTS AT END OF PERIOD	125	64
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes, net	(1)
Potomac Electric Power Co [Member]
OPERATING ACTIVITIES
Net (Loss) Income	23	24
Adjustments to reconcile net (loss) income to net cash from operating activities:
Depreciation and amortization	47	47
Deferred income taxes	26	127
Changes in:
Accounts receivable	(2)	35
Inventories	(2)	(4)
Prepaid expenses	3	4
Regulatory assets and liabilities, net	(9)	(14)
Accounts payable and accrued liabilities	(14)	(7)
Pension contributions		(85)
Pension benefit obligation, excluding contributions	4	6
Income tax-related prepayments, receivables and payables	(60)	(139)
Interest accrued	21	19
Other assets and liabilities		(3)
Net Cash (Used By) From Operating Activities	37	10
INVESTING ACTIVITIES
Investment in property, plant and equipment	(125)	(158)
Department of Energy capital reimbursement awards received	1	6
Net other investing activities	(3)	2
Net Cash Used By Investing Activities	(127)	(150)
FINANCING ACTIVITIES
Capital contribution from Parent	175
Issuances of long-term debt	250
(Reacquisitions) Issuances of short-term debt, net	(231)	130
Cost of issuances	(4)	(3)
Net other financing activities	(12)	8
Net Cash From (Used By) Financing Activities	178	135
Net Increase (Decrease) in Cash and Cash Equivalents	88	(5)
Cash and Cash Equivalents at Beginning of Period	9	12
CASH AND CASH EQUIVALENTS AT END OF PERIOD	97	7
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes, net		1
Delmarva Power & Light Co/De [Member]
OPERATING ACTIVITIES
Net (Loss) Income	26	21
Adjustments to reconcile net (loss) income to net cash from operating activities:
Depreciation and amortization	25	24
Deferred income taxes	17	41
Changes in:
Accounts receivable	(16)	16
Inventories	5	4
Regulatory assets and liabilities, net	5	(7)
Accounts payable and accrued liabilities	(9)	(8)
Pension contributions	(10)	(85)
Income tax-related prepayments, receivables and payables	1	(31)
Interest accrued	9	6
Other assets and liabilities	1	4
Net Cash (Used By) From Operating Activities	54	(15)
INVESTING ACTIVITIES
Investment in property, plant and equipment	(83)	(69)
Net other investing activities	1	(1)
Net Cash Used By Investing Activities	(82)	(70)
FINANCING ACTIVITIES
Issuances of short-term debt, net	38	87
Net other financing activities	(6)	(3)
Net Cash From (Used By) Financing Activities	32	84
Net Increase (Decrease) in Cash and Cash Equivalents	4	(1)
Cash and Cash Equivalents at Beginning of Period	6	5
CASH AND CASH EQUIVALENTS AT END OF PERIOD	10	4
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes, net
Atlantic City Electric Co [Member]
OPERATING ACTIVITIES
Net (Loss) Income	9	2
Adjustments to reconcile net (loss) income to net cash from operating activities:
Depreciation and amortization	31	28
Deferred income taxes	2	72
Changes in:
Accounts receivable	1	17
Inventories		(1)
Regulatory assets and liabilities, net	(1)	(16)
Accounts payable and accrued liabilities		(8)
Pension contributions	(30)	(30)
Income tax-related prepayments, receivables and payables	3	(63)
Other assets and liabilities	8	10
Net Cash (Used By) From Operating Activities	23	11
INVESTING ACTIVITIES
Investment in property, plant and equipment	(74)	(53)
Department of Energy capital reimbursement awards received		1
Net other investing activities	(2)
Net Cash Used By Investing Activities	(76)	(52)
FINANCING ACTIVITIES
Reacquisitions of long-term debt	(10)	(9)
Issuances of short-term debt, net	75
Net other financing activities	(8)	8
Net Cash From (Used By) Financing Activities	57	(1)
Net Increase (Decrease) in Cash and Cash Equivalents	4	(42)
Cash and Cash Equivalents at Beginning of Period	6	91
CASH AND CASH EQUIVALENTS AT END OF PERIOD	10	49
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes, net

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Derivative Instruments And Hedging Activities (Schedule Of Cash Collateral Offset Against Derivative Positions) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Derivative [Line Items]
Cash collateral pledged to counterparties with the right to reclaim	$ 2	[1]	$ 6	[1]
Cash collateral received from counterparties with the obligation to return	(1)
Delmarva Power & Light Co/De [Member]
Derivative [Line Items]
Cash collateral received from counterparties with the obligation to return	$ (1)

[1] Includes cash deposits on commodity brokerage accounts.

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Fair Value Disclosures (Tables)

3 Months Ended

Mar. 31, 2013

Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis

	Fair Value Measurements at March 31, 2013
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)
Natural gas (d)	$	1	$	1	$	—	$	—
Capacity (e)		8		—		—		8
Cash equivalents
Treasury fund		112		112		—		—
Executive deferred compensation plan assets
Money market funds		17		17		—		—
Life insurance contracts		62		—		43		19
	$	200	$	130	$	43	$	27
LIABILITIES
Derivative instruments (b)
Electricity (c)	$	4	$	—	$	4	$	—
Capacity (e)		11		—		—		11
Executive deferred compensation plan liabilities
Life insurance contracts		29		—		29		—
	$	44	$	—	$	33	$	11

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.

(b) The fair values 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 electric supply business.

(d) Represents natural gas swaps purchased by DPL as part of a natural gas hedging program approved by the DPSC.

(e) Represents derivatives associated with ACE SOCAs.

	Fair Value Measurements at December 31, 2012
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)	$	1	$	—	$	1	$	—
Capacity (e)		8		—		—		8
Cash equivalents
Treasury fund		27		27		—		—
Executive deferred compensation plan assets
Money market funds		17		17		—		—
Life insurance contracts		60		—		42		18
	$	113	$	44	$	43	$	26
LIABILITIES
Derivative instruments (b)
Electricity (c)	$	10	$	—	$	10	$	—
Natural gas (d)		4		—		—		4
Capacity (e)		11		—		—		11
Executive deferred compensation plan liabilities
Life insurance contracts		28		—		28		—
	$	53	$	—	$	38	$	15

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.

(b) The fair values 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 electric supply business.

(d) Represents natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

(e) Represents derivatives associated with ACE SOCAs.

Summary Of Primary Unobservable Inputs Used To Determine Fair Value Of Level 3 Instruments And Range Of Values That Could Be Used For Those Inputs

Type of Instrument	Fair Value at March 31, 2013			Valuation Technique		Unobservable Input		Range
	(millions of dollars)
Capacity contracts, net	$	(3	)		Discounted cash flow		Discount rate	6% - 8%

Type of Instrument	Fair Value at December 31, 2012			Valuation Technique	Unobservable Input	Range
	(millions of dollars)
Natural gas options	$	(4	)	Option model	Volatility factor	1.57 - 2.00
Capacity contracts, net		(3	)	Discounted cash flow	Discount rate	5% - 9%

Reconciliations Of Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

	Three Months Ended March 31, 2013
	Natural Gas			Life Insurance Contracts		Capacity
	(millions of dollars)
Beginning balance as of January 1	$	(4	)	$	18	$	(3	)
Total gains (losses) (realized and unrealized):
Included in income		—			1		—
Included in accumulated other comprehensive loss		—			—		—
Included in regulatory liabilities		—			—		—
Purchases		—			—		—
Issuances		—			—		—
Settlements		4			—		—
Transfers in (out) of level 3		—			—		—
Ending balance as of March 31	$	—		$	19	$	(3	)

	Three Months Ended March 31, 2012
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(15	)	$	17
Total gains (losses) (realized and unrealized):
Included in income		—			1
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(3	)		—
Purchases		—			—
Issuances		—			—
Settlements		6			—
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	(12	)	$	18

Gains On Level 3 Instruments Included In Income

	Three Months Ended March 31,
	2013		2012
	(millions of dollars)
Total net gains included in income for the period	$	1	$	1
Change in unrealized gains relating to assets still held at reporting date	$	1	$	1

Fair Value Of Financial Liabilities Measured On Recurring Basis

	Fair Value Measurements at March 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	5,194	$	386	$	4,326	$	482
Transition Bonds issued by ACE Funding (b)		327		—		327		—
Long-term project funding		13		—		—		13
	$	5,534	$	386	$	4,653	$	495

(a) The carrying amount for Long-term debt is $4,426 million as of March 31, 2013.

(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $285 million as of March 31, 2013.

	Fair Value Measurements at December 31, 2012
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	5,004	$	204	$	4,313	$	487
Transition Bonds issued by ACE Funding (b)		341		—		341		—
Long-term project funding		13		—		—		13
	$	5,358	$	204	$	4,654	$	500

(a) The carrying amount for Long-term debt is $4,177 million as of December 31, 2012.

(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $295 million as of December 31, 2012.

Delmarva Power & Light Co/De [Member]

Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis

	Fair Value Measurements at March 31, 2013
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)
Natural gas (c)	$	1	$	1	$	—	$	—
Executive deferred compensation plan assets
Money market funds		2		2		—		—
Life insurance contracts		1		—		—		1
	$	4	$	3	$	—	$	1
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.

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

(c) Represents natural gas swaps purchased by DPL as part of a natural gas hedging program approved by the DPSC.

	Fair Value Measurements at December 31, 2012
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 (c)	$	4	$	—	$	—	$	4
	$	4	$	—	$	—	$	4

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.

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

(c) Represents natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

Summary Of Primary Unobservable Inputs Used To Determine Fair Value Of Level 3 Instruments And Range Of Values That Could Be Used For Those Inputs

Type of Instrument	Fair Value at December 31, 2012			Valuation Technique		Unobservable Input		Range
	(millions of dollars)
Natural gas options	$	(4	)		Option model		Volatility factor		1.57 – 2.00

Reconciliations Of Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

	Three Months Ended March  31, 2013
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(4	)	$	1
Total gains (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		—			—
Purchases		—			—
Issuances		—			—
Settlements		4			—
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	—		$	1

	Three Months Ended March 31, 2012
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(15	)	$	1
Total gains (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(3	)		—
Purchases		—			—
Issuances		—			—
Settlements		6			—
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	(12	)	$	1

Fair Value Of Financial Liabilities Measured On Recurring Basis

	Fair Value Measurements at March 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	968	$	15	$	841	$	112
	$	968	$	15	$	841	$	112

(a) The carrying amount for Long-term debt is $917 million as of March 31, 2013.

	Fair Value Measurements at December 31, 2012
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	990	$	—	$	877	$	113
	$	990	$	—	$	877	$	113

(a) The carrying amount for Long-term debt is $917 million as of December 31, 2012.

Atlantic City Electric Co [Member]

Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis

	Fair Value Measurements at March 31, 2013
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)
Capacity (c)	$	8	$	—	$	—	$	8
Cash equivalents
Treasury fund		26		26		—		—
	$	34	$	26	$	—	$	8
LIABILITIES
Derivative instruments (b)
Capacity (c)	$	11	$	—	$	—	$	11
Executive deferred compensation plan liabilities
Life insurance contracts		1		—		1		—
	$	12	$	—	$	1	$	11

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.

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

(c) Represents derivatives associated with ACE SOCAs.

	Fair Value Measurements at December 31, 2012
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)
Capacity (c)	$	8	$	—	$	—	$	8
Cash equivalents
Treasury fund		27		27		—		—
	$	35	$	27	$	—	$	8
LIABILITIES
Derivative instruments (b)
Capacity (c)	$	11	$	—	$	—	$	11
Executive deferred compensation plan liabilities
Life insurance contracts		1		—		1		—
	$	12	$	—	$	1	$	11

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.

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

(c) Represents derivatives associated with ACE SOCAs.

Summary Of Primary Unobservable Inputs Used To Determine Fair Value Of Level 3 Instruments And Range Of Values That Could Be Used For Those Inputs

Type of Instrument	Fair Value at March 31, 2013			Valuation Technique		Unobservable Input		Range
	(millions of dollars)
Capacity contracts, net	$	(3	)		Discounted cash flow		Discount rate		6% - 8%

Type of Instrument	Fair Value at December 31, 2012			Valuation Technique		Unobservable Input		Range
	(millions of dollars)
Capacity contracts, net	$	(3	)		Discounted cash flow		Discount rate		5% - 9%

Reconciliations Of Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

	Capacity
	Three Months Ended March 31, 2013
	(millions of dollars)
Beginning balance as of January 1	$	(3	)
Total gains (losses) (realized and unrealized):
Included in income		—
Included in accumulated other comprehensive loss		—
Included in regulatory liabilities and regulatory assets		—
Purchases		—
Issuances		—
Settlements		—
Transfers in (out) of level 3		—
Ending balance as of March 31	$	(3	)

Fair Value Of Financial Liabilities Measured On Recurring Basis

	Fair Value Measurements at March 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,007	$	—	$	877	$	130
Transition Bonds issued by ACE Funding (b)		327		—		327		—
	$	1,334	$	—	$	1,204	$	130

(a) The carrying amount for Long-term debt is $829 million as of March 31, 2013.

(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $285 million as of March 31, 2013.

	Fair Value Measurements at December 31, 2012
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,016	$	—	$	884	$	132
Transition Bonds issued by ACE Funding (b)		341		—		341		—
	$	1,357	$	—	$	1,225	$	132

(a) The carrying amount for Long-term debt is $829 million as of December 31, 2012.

(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $295 million as of December 31, 2012.

Potomac Electric Power Co [Member]

Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis

	Fair Value Measurements at March 31, 2013
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	$	85	$	85	$	—	$	—
Executive deferred compensation plan assets
Money market funds		14		14		—		—
Life insurance contracts		57		—		39		18
	$	156	$	99	$	39	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	8	$	—	$	8	$	—
	$	8	$	—	$	8	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.

	Fair Value Measurements at December 31, 2012
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		56		—		38		18
	$	71	$	15	$	38	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	9	$	—	$	9	$	—
	$	9	$	—	$	9	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.

Reconciliations Of Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

	Life Insurance Contracts
	Three Months Ended March 31,
	2013			2012
	(millions of dollars)
Beginning balance as of January 1	$	18		$	17
Total gains (losses) (realized and unrealized):
Included in income		1			1
Included in accumulated other comprehensive loss		—			—
Purchases		—			—
Issuances		(1	)		—
Settlements		—			—
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	18		$	18

Gains On Level 3 Instruments Included In Income

	Three Months Ended March  31,
	2013		2012
	(millions of dollars)
Total gains included in income for the period	$	1	$	1
Change in unrealized gains relating to assets still held at reporting date	$	1	$	1

Fair Value Of Financial Liabilities Measured On Recurring Basis

	Fair Value Measurements at March 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	2,387	$	371	$	2,016	$	—
	$	2,387	$	371	$	2,016	$	—

(a) The carrying amount for Long-term debt is $1,951 million as of March 31, 2013.

	Fair Value Measurements at December 31, 2012
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	2,160	$	204	$	1,956	$	—
	$	2,160	$	204	$	1,956	$	—

(a) The carrying amount for Long-term debt is $1,701 million as of December 31, 2012.

XML

Derivative Instruments And Hedging Activities (Net Unrealized Derivative Gain (Loss) Deferred As Regulatory Asset Or Liability) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
PHI [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Net unrealized gain (loss) arising during the period	$ 2	$ (4)
Net realized loss recognized during the period	(4)	(7)
Delmarva Power & Light Co/De [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Net unrealized gain (loss) arising during the period	2	(4)
Net realized loss recognized during the period	$ (4)	$ (7)

XML

Fair Value Disclosures

3 Months Ended

Mar. 31, 2013

Fair Value Disclosures

(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).

The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2013 and December 31, 2012. 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.

	Fair Value Measurements at March 31, 2013
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)
Natural gas (d)	$	1	$	1	$	—	$	—
Capacity (e)		8		—		—		8
Cash equivalents
Treasury fund		112		112		—		—
Executive deferred compensation plan assets
Money market funds		17		17		—		—
Life insurance contracts		62		—		43		19
	$	200	$	130	$	43	$	27
LIABILITIES
Derivative instruments (b)
Electricity (c)	$	4	$	—	$	4	$	—
Capacity (e)		11		—		—		11
Executive deferred compensation plan liabilities
Life insurance contracts		29		—		29		—
	$	44	$	—	$	33	$	11

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.

(b) The fair values 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 electric supply business.

(d) Represents natural gas swaps purchased by DPL as part of a natural gas hedging program approved by the DPSC.

(e) Represents derivatives associated with ACE SOCAs.

	Fair Value Measurements at December 31, 2012
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)	$	1	$	—	$	1	$	—
Capacity (e)		8		—		—		8
Cash equivalents
Treasury fund		27		27		—		—
Executive deferred compensation plan assets
Money market funds		17		17		—		—
Life insurance contracts		60		—		42		18
	$	113	$	44	$	43	$	26
LIABILITIES
Derivative instruments (b)
Electricity (c)	$	10	$	—	$	10	$	—
Natural gas (d)		4		—		—		4
Capacity (e)		11		—		—		11
Executive deferred compensation plan liabilities
Life insurance contracts		28		—		28		—
	$	53	$	—	$	38	$	15

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.

(b) The fair values 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 electric supply business.

(d) Represents natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

(e) Represents derivatives associated with ACE SOCAs.

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).

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 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 March 31, 2013. Level 2 power swaps are provided by a pricing service that uses liquid trading hub prices or liquid hub prices plus a congestion adder to estimate the fair value at zonal locations within trading hubs.

Executive deferred compensation plan assets consist of life insurance policies and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued 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 and can be liquidated for the value of the underlying

assets as of March 31, 2013. 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.

The value of certain employment agreement obligations is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data.

Level 3 – Pricing inputs that are significant and 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 used by DPL as part of a natural gas hedging program approved by the DPSC and capacity under the SOCAs entered into by ACE:

• DPL applies a Black-Scholes model to value its options with inputs, such as forward price curves, contract prices, contract volumes, the risk-free rate and implied volatility factors, that are based on a range of historical NYMEX option prices. DPL maintains valuation policies and procedures and reviews the validity and relevance of the inputs used to estimate the fair value of its options. As of March 31, 2013, all of these contracts classified as level 3 derivative instruments have settled.

• ACE used a discounted cash flow methodology to estimate the fair value of the capacity derivatives embedded in the SOCAs. ACE utilized an external valuation specialist to estimate annual zonal PJM capacity prices through the 2030-2031 auction. The capacity price forecast was based on various assumptions that impact the cost of constructing new generation facilities, including zonal load forecasts, zonal fuel and energy prices, generation capacity and transmission planning, and environmental legislation and regulation. ACE reviewed the assumptions and resulting capacity price forecast for reasonableness. ACE used the capacity price forecast to estimate future cash flows. A significant change in the forecasted prices would have a significant impact on the estimated fair value of the SOCAs. ACE employed a discount rate reflective of the estimated weighted average cost of capital for merchant generation companies since payments under the SOCAs are contingent on providing generation capacity.

The tables below summarize the primary unobservable inputs used to determine the fair value of PHI’s level 3 instruments and the range of values that could be used for those inputs as of March 31, 2013 and December 31, 2012:

Type of Instrument	Fair Value at March 31, 2013			Valuation Technique		Unobservable Input		Range
	(millions of dollars)
Capacity contracts, net	$	(3	)		Discounted cash flow		Discount rate	6% - 8%

Type of Instrument	Fair Value at December 31, 2012			Valuation Technique	Unobservable Input	Range
	(millions of dollars)
Natural gas options	$	(4	)	Option model	Volatility factor	1.57 - 2.00
Capacity contracts, net		(3	)	Discounted cash flow	Discount rate	5% - 9%

PHI used values within these ranges as part of its fair value estimates. A significant change in any of the unobservable inputs within these ranges would have an insignificant impact on the reported fair value as of March 31, 2013 and December 31, 2012.

Executive deferred compensation plan assets and liabilities include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by PHI for reasonableness.

Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (Level 3) for the three months ended March 31, 2013 and 2012 are shown below:

	Three Months Ended March 31, 2013
	Natural Gas			Life Insurance Contracts		Capacity
	(millions of dollars)
Beginning balance as of January 1	$	(4	)	$	18	$	(3	)
Total gains (losses) (realized and unrealized):
Included in income		—			1		—
Included in accumulated other comprehensive loss		—			—		—
Included in regulatory liabilities		—			—		—
Purchases		—			—		—
Issuances		—			—		—
Settlements		4			—		—
Transfers in (out) of level 3		—			—		—
Ending balance as of March 31	$	—		$	19	$	(3	)

	Three Months Ended March 31, 2012
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(15	)	$	17
Total gains (losses) (realized and unrealized):
Included in income		—			1
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(3	)		—
Purchases		—			—
Issuances		—			—
Settlements		6			—
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	(12	)	$	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:

	Three Months Ended March 31,
	2013		2012
	(millions of dollars)
Total net gains included in income for the period	$	1	$	1
Change in unrealized gains relating to assets still held at reporting date	$	1	$	1

Other Financial Instruments

The estimated fair values of PHI’s debt instruments that are measured at amortized cost in PHI’s consolidated financial statements and the associated level of the estimates within the fair value hierarchy as of March 31, 2013 and December 31, 2012 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy 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, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt categorized as level 1 is based on actual quoted trade prices for the debt in active markets on the measurement date.

The fair value of Long-term debt and Transition Bonds issued by ACE Funding categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt in active markets, but not on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and PHI reviews the methodologies and results.

The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient. The Long-Term project funding represents debt instruments issued by Pepco Energy Services related to its energy savings contracts. Long-Term project funding is categorized as level 3 because PHI concluded that the amortized cost carrying amounts for these instruments approximates fair value, which does not represent a quoted price in an active market.

	Fair Value Measurements at March 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	5,194	$	386	$	4,326	$	482
Transition Bonds issued by ACE Funding (b)		327		—		327		—
Long-term project funding		13		—		—		13
	$	5,534	$	386	$	4,653	$	495

(a) The carrying amount for Long-term debt is $4,426 million as of March 31, 2013.

(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $285 million as of March 31, 2013.

	Fair Value Measurements at December 31, 2012
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	5,004	$	204	$	4,313	$	487
Transition Bonds issued by ACE Funding (b)		341		—		341		—
Long-term project funding		13		—		—		13
	$	5,358	$	204	$	4,654	$	500

(a) The carrying amount for Long-term debt is $4,177 million as of December 31, 2012.

(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $295 million as of December 31, 2012.

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

Potomac Electric Power Co [Member]

Fair Value Disclosures

(10) 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).

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 March 31, 2013 and December 31, 2012. 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 March 31, 2013
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	$	85	$	85	$	—	$	—
Executive deferred compensation plan assets
Money market funds		14		14		—		—
Life insurance contracts		57		—		39		18
	$	156	$	99	$	39	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	8	$	—	$	8	$	—
	$	8	$	—	$	8	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.

	Fair Value Measurements at December 31, 2012
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		56		—		38		18
	$	71	$	15	$	38	$	18
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	9	$	—	$	9	$	—
	$	9	$	—	$	9	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.

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.

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 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 and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued 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 and can be liquidated for the value of the underlying assets as of March 31, 2013. 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.

The value of certain employment agreement obligations is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data.

Level 3 – Pricing inputs that are significant and 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 include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by Pepco for reasonableness.

Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (level 3) for the three months ended March 31, 2013 and 2012, are shown below:

	Life Insurance Contracts
	Three Months Ended March 31,
	2013			2012
	(millions of dollars)
Beginning balance as of January 1	$	18		$	17
Total gains (losses) (realized and unrealized):
Included in income		1			1
Included in accumulated other comprehensive loss		—			—
Purchases		—			—
Issuances		(1	)		—
Settlements		—			—
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	18		$	18

The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other Operation and Maintenance expense for the periods below were as follows:

	Three Months Ended March  31,
	2013		2012
	(millions of dollars)
Total gains included in income for the period	$	1	$	1
Change in unrealized gains relating to assets still held at reporting date	$	1	$	1

Other Financial Instruments

The estimated fair values of Pepco’s debt instruments that are measured at amortized cost in Pepco’s financial statements and the associated level of the estimates within the fair value hierarchy as of March 31, 2013 and December 31, 2012 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy 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, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt categorized as level 1 is based on actual quoted trade prices for the debt in active markets on the measurement date.

The fair value of Long-term debt categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt in active markets, but not on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and Pepco reviews the methodologies and results.

	Fair Value Measurements at March 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	2,387	$	371	$	2,016	$	—
	$	2,387	$	371	$	2,016	$	—

(a) The carrying amount for Long-term debt is $1,951 million as of March 31, 2013.

	Fair Value Measurements at December 31, 2012
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	2,160	$	204	$	1,956	$	—
	$	2,160	$	204	$	1,956	$	—

(a) The carrying amount for Long-term debt is $1,701 million as of December 31, 2012.

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

Delmarva Power & Light Co/De [Member]

Fair Value Disclosures

(12) 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).

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 March 31, 2013 and December 31, 2012. 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 March 31, 2013
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)
Natural gas (c)	$	1	$	1	$	—	$	—
Executive deferred compensation plan assets
Money market funds		2		2		—		—
Life insurance contracts		1		—		—		1
	$	4	$	3	$	—	$	1
LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	1	$	—	$	1	$	—
	$	1	$	—	$	1	$	—

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.

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

(c) Represents natural gas swaps purchased by DPL as part of a natural gas hedging program approved by the DPSC.

	Fair Value Measurements at December 31, 2012
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 (c)	$	4	$	—	$	—	$	4
	$	4	$	—	$	—	$	4

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.

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

(c) Represents natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.

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 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 2 executive deferred compensation plan liabilities associated with the life insurance policies represent 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 that are significant and 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 as of December 31, 2012, represent natural gas options used by DPL as part of a natural gas hedging program approved by the DPSC. DPL applies a Black-Scholes model to value its options with inputs, such as forward price curves, contract prices, contract volumes, the risk-free rate and implied volatility factors that are based on a range of historical NYMEX option prices. DPL maintains valuation policies and procedures and reviews the validity and relevance of the inputs used to estimate the fair value of its options. As of March 31, 2013, all of these contracts classified as level 3 derivative instruments have settled.

The table below summarizes the primary unobservable input used to determine the fair value of DPL’s level 3 instruments and the range of values that could be used for the input as of December 31, 2012:

Type of Instrument	Fair Value at December 31, 2012			Valuation Technique		Unobservable Input		Range
	(millions of dollars)
Natural gas options	$	(4	)		Option model		Volatility factor		1.57 – 2.00

DPL used values within this range as part of its fair value estimates. A significant change in the unobservable input within this range would have an insignificant impact on the reported fair value as of December 31, 2012.

Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by DPL for reasonableness.

Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (level 3) for the three months ended March 31, 2013 and 2012, are shown below:

	Three Months Ended March  31, 2013
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(4	)	$	1
Total gains (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		—			—
Purchases		—			—
Issuances		—			—
Settlements		4			—
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	—		$	1

	Three Months Ended March 31, 2012
	Natural Gas			Life Insurance Contracts
	(millions of dollars)
Beginning balance as of January 1	$	(15	)	$	1
Total gains (losses) (realized and unrealized):
Included in income		—			—
Included in accumulated other comprehensive loss		—			—
Included in regulatory liabilities		(3	)		—
Purchases		—			—
Issuances		—			—
Settlements		6			—
Transfers in (out) of level 3		—			—
Ending balance as of March 31	$	(12	)	$	1

Other Financial Instruments

The estimated fair values of DPL’s debt instruments that are measured at amortized cost in DPL’s financial statements and the associated level of the estimates within the fair value hierarchy as of March 31, 2013 and December 31, 2012 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy 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, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt categorized as level 1 is based on actual quoted trade prices for the debt in active markets on the measurement date.

The fair value of Long-term debt categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt in active markets, but not on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and DPL reviews the methodologies and results.

The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient.

	Fair Value Measurements at March 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	968	$	15	$	841	$	112
	$	968	$	15	$	841	$	112

(a) The carrying amount for Long-term debt is $917 million as of March 31, 2013.

	Fair Value Measurements at December 31, 2012
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	990	$	—	$	877	$	113
	$	990	$	—	$	877	$	113

(a) The carrying amount for Long-term debt is $917 million as of December 31, 2012.

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

Atlantic City Electric Co [Member]

Fair Value Disclosures

(11) 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).

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 March 31, 2013 and December 31, 2012. 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.

	Fair Value Measurements at March 31, 2013
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)
Capacity (c)	$	8	$	—	$	—	$	8
Cash equivalents
Treasury fund		26		26		—		—
	$	34	$	26	$	—	$	8
LIABILITIES
Derivative instruments (b)
Capacity (c)	$	11	$	—	$	—	$	11
Executive deferred compensation plan liabilities
Life insurance contracts		1		—		1		—
	$	12	$	—	$	1	$	11

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2013.

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

(c) Represents derivatives associated with ACE SOCAs.

	Fair Value Measurements at December 31, 2012
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)
Capacity (c)	$	8	$	—	$	—	$	8
Cash equivalents
Treasury fund		27		27		—		—
	$	35	$	27	$	—	$	8
LIABILITIES
Derivative instruments (b)
Capacity (c)	$	11	$	—	$	—	$	11
Executive deferred compensation plan liabilities
Life insurance contracts		1		—		1		—
	$	12	$	—	$	1	$	11

(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.

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

(c) Represents derivatives associated with ACE SOCAs.

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 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 that are significant and 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 represent capacity under the SOCAs entered into by ACE.

ACE used a discounted cash flow methodology to estimate the fair value of the capacity derivatives embedded in the SOCAs. ACE utilized an external valuation specialist to estimate annual zonal PJM capacity prices through the 2030-2031 auction. The capacity price forecast was based on various assumptions that impact the cost of constructing new generation facilities, including zonal load forecasts, zonal fuel and energy prices, generation capacity and transmission planning, and environmental legislation and regulation. ACE reviewed the assumptions and resulting capacity price forecast for reasonableness. ACE used the capacity price forecast to estimate future cash flows. A significant change in the forecasted prices would have a significant impact on the estimated fair value of the SOCAs. ACE employed a discount rate reflective of the estimated weighted average cost of capital for merchant generation companies since payments under the SOCAs are contingent on providing generation capacity.

The tables below summarize the primary unobservable inputs used to determine the fair value of ACE’s level 3 instruments and the range of values that could be used for those inputs as of March 31, 2013 and December 31, 2012:

Type of Instrument	Fair Value at March 31, 2013			Valuation Technique		Unobservable Input		Range
	(millions of dollars)
Capacity contracts, net	$	(3	)		Discounted cash flow		Discount rate		6% - 8%

Type of Instrument	Fair Value at December 31, 2012			Valuation Technique		Unobservable Input		Range
	(millions of dollars)
Capacity contracts, net	$	(3	)		Discounted cash flow		Discount rate		5% - 9%

ACE used values within these ranges as part of its fair value estimates. A significant change in any of the unobservable inputs within these ranges would have an insignificant impact on the reported fair value as of March 31, 2013 and December 31, 2012.

A reconciliation of the beginning and ending balances of ACE’s fair value measurements using significant unobservable inputs (level 3) for the three months ended March 31, 2013 is shown below:

	Capacity
	Three Months Ended March 31, 2013
	(millions of dollars)
Beginning balance as of January 1	$	(3	)
Total gains (losses) (realized and unrealized):
Included in income		—
Included in accumulated other comprehensive loss		—
Included in regulatory liabilities and regulatory assets		—
Purchases		—
Issuances		—
Settlements		—
Transfers in (out) of level 3		—
Ending balance as of March 31	$	(3	)

Other Financial Instruments

The estimated fair values of ACE’s debt instruments that are measured at amortized cost in ACE’s consolidated financial statements and the associated levels of the estimates within the fair value hierarchy as of March 31, 2013 and December 31, 2012 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy 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, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.

The fair value of Long-term debt and Transition Bonds issued by ACE Funding categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt in active markets, but not on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and ACE reviews the methodologies and results.

The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient.

	Fair Value Measurements at March 31, 2013
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,007	$	—	$	877	$	130
Transition Bonds issued by ACE Funding (b)		327		—		327		—
	$	1,334	$	—	$	1,204	$	130

(a) The carrying amount for Long-term debt is $829 million as of March 31, 2013.

(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $285 million as of March 31, 2013.

	Fair Value Measurements at December 31, 2012
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)	$	1,016	$	—	$	884	$	132
Transition Bonds issued by ACE Funding (b)		341		—		341		—
	$	1,357	$	—	$	1,225	$	132

(a) The carrying amount for Long-term debt is $829 million as of December 31, 2012.

(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $295 million as of December 31, 2012.

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

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Commitments And Contingencies (Tables)

3 Months Ended

Mar. 31, 2013

Schedule Of Accrued Liabilities For Environmental Exposures

			Legacy Generation
	Transmission and  Distribution		Regulated		Non- Regulated		Other		Total
	(millions of dollars)
Beginning balance as of January 1	$	15	$	7	$	5	$	2	$	29
Accruals		—		—		—		—		—
Payments		—		1		—		—		1
Ending balance as of March 31		15		6		5		2		28
Less amounts in Other current liabilities		2		1		—		2		5
Amounts in Other deferred credits	$	13	$	5	$	5	$	—	$	23

Schedule Of Commitments And Obligations

	Guarantor
	PHI		Pepco		DPL		ACE		Total
Energy procurement obligations of Pepco Energy Services (a)	$	75	$	—	$	—	$	—	$	75
Guarantees associated with disposal of Conectiv Energy assets (b)		13		—		—		—		13
Guaranteed lease residual values (c)		2		5		7		4		18
Total	$	90	$	5	$	7	$	4	$	106

Delmarva Power & Light Co/De [Member]

Schedule Of Accrued Liabilities For Environmental Exposures

	Transmission and Distribution		Legacy Generation  - Regulated		Other		Total
	(millions of dollars)
Beginning balance as of January 1	$	1	$	3	$	2	$	6
Accruals		—		—		—		—
Payments		—		1		—		1
Ending balance as of March 31		1		2		2		5
Less amounts in Other Current Liabilities		1		1		2		4
Amounts in Other Deferred Credits	$	—	$	1	$	—	$	1

Atlantic City Electric Co [Member]

Schedule Of Accrued Liabilities For Environmental Exposures

	Legacy Generation - Regulated
	(millions of dollars)
Beginning balance as of January 1	$	1
Accruals		—
Payments		—
Ending balance as of March 31		1
Less amounts in Other Current Liabilities		—
Amounts in Other Deferred Credits	$	1

Potomac Electric Power Co [Member]

Schedule Of Accrued Liabilities For Environmental Exposures

	Transmission and Distribution		Legacy Generation - Regulated		Total
	(millions of dollars)
Beginning balance as of January 1	$	14	$	3	$	17
Accruals		—		—		—
Payments		—		—		—
Ending balance as of March 31		14		3		17
Less amounts in Other current liabilities		1		—		1
Amounts in Other deferred credits	$	13	$	3	$	16

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Accumulated Other Comprehensive Loss

3 Months Ended

Mar. 31, 2013

Equity [Abstract]

Accumulated Other Comprehensive Loss

(16) ACCUMULATED OTHER COMPREHENSIVE LOSS

The components of Pepco Holdings’ AOCL relating to continuing operations are as follows. For additional information, see the consolidated statements of comprehensive income.

	Three Months Ended March 31,
	2013			2012
Balance, beginning of period	$	(45	)	$	(50	)
Commodity Derivatives
Balance, beginning of period		(3	)		(16	)
Amount of net pre-tax loss reclassified into income:
Fuel and Purchased Energy expense		3			7
Revenue		—			—
Total net pre-tax loss reclassified into income		3			7
Income Tax expense		(1	)		(2	)
Net change during period		2			5
Balance, end of period		(1	)		(11	)
Treasury Lock
Balance, beginning of period		(10	)		(10	)
Amount of net pre-tax loss reclassified into income:
Interest expense		—			—
Total net pre-tax loss reclassified into income		—			—
Income Tax expense		—			—
Net change during period		—			—
Balance, end of period		(10	)		(10	)
Pension and Other Postretirement Benefit Plans
Balance, beginning of period		(32	)		(24	)
Amount of net pre-tax loss reclassified into income:
Other Operation and Maintenance expense		2			1
Total net pre-tax loss reclassified into income		2			1
Income Tax expense		(1	)		(1	)
Net change during period		1			—
Balance, end of period		(31	)		(24	)
Balance, end of period	$	(42	)	$	(45	)

XML

Fair Value Disclosures (Summary Of Primary Unobservable Inputs Used To Determine Fair Value Of Level 3 Instruments And Range Of Values That For Those Inputs) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2012
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value of financial instrument	5,534	5,358
Delmarva Power & Light Co/De [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value of financial instrument	968	990
Atlantic City Electric Co [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value of financial instrument	1,334	1,357
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value of financial instrument	495	500
Significant Unobservable Inputs (Level 3) [Member] | Natural Gas Options [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value of financial instrument		(4)
Significant Unobservable Inputs (Level 3) [Member] | Capacity [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value of financial instrument	(3)	(3)
Significant Unobservable Inputs (Level 3) [Member] | Delmarva Power & Light Co/De [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value of financial instrument	112	113
Significant Unobservable Inputs (Level 3) [Member] | Delmarva Power & Light Co/De [Member] | Natural Gas Options [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value of financial instrument		(4)
Significant Unobservable Inputs (Level 3) [Member] | Atlantic City Electric Co [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value of financial instrument	130	132
Significant Unobservable Inputs (Level 3) [Member] | Atlantic City Electric Co [Member] | Capacity [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value of financial instrument	(3)	(3)
Minimum [Member] | Significant Unobservable Inputs (Level 3) [Member] | Capacity [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Discounted cash flow, Discount rate	6.00%
Maximum [Member] | Significant Unobservable Inputs (Level 3) [Member] | Capacity [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Discounted cash flow, Discount rate	8.00%
Derivative [Member] | Minimum [Member] | Significant Unobservable Inputs (Level 3) [Member] | Natural Gas Options [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Volatility Factor, Range		1.57
Derivative [Member] | Minimum [Member] | Significant Unobservable Inputs (Level 3) [Member] | Capacity [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Discounted cash flow, Discount rate		5.00%
Derivative [Member] | Minimum [Member] | Significant Unobservable Inputs (Level 3) [Member] | Delmarva Power & Light Co/De [Member] | Natural Gas Options [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Volatility Factor, Range		1.57
Derivative [Member] | Minimum [Member] | Significant Unobservable Inputs (Level 3) [Member] | Atlantic City Electric Co [Member] | Capacity [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Discounted cash flow, Discount rate	6.00%	5.00%
Derivative [Member] | Maximum [Member] | Significant Unobservable Inputs (Level 3) [Member] | Natural Gas Options [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Volatility Factor, Range		2.00
Derivative [Member] | Maximum [Member] | Significant Unobservable Inputs (Level 3) [Member] | Capacity [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Discounted cash flow, Discount rate		9.00%
Derivative [Member] | Maximum [Member] | Significant Unobservable Inputs (Level 3) [Member] | Delmarva Power & Light Co/De [Member] | Natural Gas Options [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Volatility Factor, Range		2.00
Derivative [Member] | Maximum [Member] | Significant Unobservable Inputs (Level 3) [Member] | Atlantic City Electric Co [Member] | Capacity [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Discounted cash flow, Discount rate	8.00%	9.00%

XML

Consolidated Statement Of Equity (USD $) In Millions, except Share data	Total USD ($)	Common Stock [Member] USD ($)	Premium On Stock [Member] USD ($)	Retained Earnings [Member] USD ($)	Accumulated Other Comprehensive (Loss) Income [Member] USD ($)	Potomac Electric Power Co [Member] USD ($)	Potomac Electric Power Co [Member] Common Stock [Member]	Potomac Electric Power Co [Member] Premium On Stock [Member] USD ($)	Potomac Electric Power Co [Member] Retained Earnings [Member] USD ($)	Delmarva Power & Light Co/De [Member] USD ($)	Delmarva Power & Light Co/De [Member] Common Stock [Member]	Delmarva Power & Light Co/De [Member] Premium On Stock [Member] USD ($)	Delmarva Power & Light Co/De [Member] Retained Earnings [Member] USD ($)	Atlantic City Electric Co [Member] USD ($)	Atlantic City Electric Co [Member] Common Stock [Member] USD ($)	Atlantic City Electric Co [Member] Premium On Stock [Member] USD ($)	Atlantic City Electric Co [Member] Retained Earnings [Member] USD ($)
BALANCE at Dec. 31, 2012	$ 4,446	$ 2	$ 3,383	$ 1,109	$ (48)	$ 1,643		$ 755	$ 888	$ 985		$ 407	$ 578	$ 802	$ 26	$ 576	$ 200
Common Stock, Shares, Outstanding, Beginning Balance at Dec. 31, 2012	230,015,427	230,015,427				100	100			1,000	1,000			8,546,017	8,546,017
Net (Loss) Income	(430)			(430)		23			23	26			26	9			9
Other comprehensive income	6				6
Capital contribution from Parent						175		175
Dividends on common stock	(67)			(67)
Original issue shares, net	321		321
Original issue shares, net, shares		18,268,100
Shareholder DRP original shares, value	8		8
Shareholder DRP original shares, shares		370,787
Net activity related to stock-based awards	(6)	(102,933)	(6)
BALANCE at Mar. 31, 2013	$ 4,278	$ 2	$ 3,706	$ 612	$ (42)	$ 1,841		$ 930	$ 911	$ 1,011		$ 407	$ 604	$ 811	$ 26	$ 576	$ 209
Common Stock, Shares, Outstanding, Ending Balance at Mar. 31, 2013	248,551,381	248,551,381				100	100			1,000	1,000			8,546,017	8,546,017

XML

Consolidated Statements Of Comprehensive (Loss) Income (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Statement Of Income And Comprehensive Income [Abstract]
Net (Loss) Income	$ (430)	$ 68
Other Comprehensive Income from Continuing Operations
Losses on commodity derivatives designated as cash flow hedges reclassified into income	3	7
Pension and other postretirement benefit plans	2	1
Other comprehensive income, before income taxes	5	8
Income tax expense related to other comprehensive income	2	3
Other comprehensive income from continuing operations, net of income taxes	3	5
Other Comprehensive Income from Discontinued Operations, Net of Income Taxes	3	3
Comprehensive (Loss) Income	$ (424)	$ 76

XML

Pension And Other Postretirement Benefits

3 Months Ended

Mar. 31, 2013

Pension And Other Postretirement Benefits

(9) PENSION AND OTHER POSTRETIREMENT BENEFITS

The following Pepco Holdings information is for the three months ended March 31, 2013 and 2012:

	Pension Benefits						Other Postretirement Benefits
	2013			2012			2013			2012
	(millions of dollars)
Service cost	$	13		$	11		$	2		$	1
Interest cost		25			26			8			9
Expected return on plan assets		(37	)		(34	)		(5	)		(5	)
Amortization of prior service cost		—			—			(1	)		(1	)
Amortization of net actuarial loss		16			14			4			5
Net periodic benefit cost	$	17		$	17		$	8		$	9

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. 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 target liability as defined under the Pension Protection Act of 2006. In the first quarter of 2013, PHI, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $20 million, $10 million and $30 million, respectively. In the first quarter of 2012, Pepco, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $85 million, $85 million and $30 million, respectively, which brought the PHI Retirement Plan assets to the funding target level for 2012 under the Pension Protection Act.

Potomac Electric Power Co [Member]

Pension And Other Postretirement Benefits

(7) PENSION AND OTHER POSTRETIREMENT BENEFITS

Pepco accounts for its participation in its parent’s single-employer plans, Pepco Holding’s non-contributory 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 March 31, 2013 and 2012, before intercompany allocations from the PHI Service Company, were $25 million and $26 million, respectively. Pepco’s allocated share was $8 million and $11 million, respectively, for the three months ended March 31, 2013 and 2012.

In the first quarter of 2012, Pepco made a discretionary tax-deductible contribution to the PHI Retirement Plan of $85 million.

Delmarva Power & Light Co/De [Member]

Pension And Other Postretirement Benefits

(8) PENSION AND OTHER POSTRETIREMENT BENEFITS

DPL accounts for its participation in its parent’s single-employer plans, Pepco Holdings’ non-contributory 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 March 31, 2013 and 2012, before intercompany allocations from the PHI Service Company, were $25 million and $26 million, respectively. DPL’s allocated share was $4 million and $6 million, respectively, for the three months ended March 31, 2013 and 2012.

In the first quarter of 2013, DPL made a discretionary tax-deductible contribution to the PHI Retirement Plan of $10 million. In the first quarter of 2012, DPL made a discretionary tax-deductible contribution to the PHI Retirement Plan of $85 million.

Atlantic City Electric Co [Member]

Pension And Other Postretirement Benefits

(7) PENSION AND OTHER POSTRETIREMENT BENEFITS

ACE accounts for its participation in its parent’s single-employer plans, Pepco Holdings’ non-contributory 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 March 31, 2013 and 2012, before intercompany allocations from the PHI Service Company, were $25 million and $26 million, respectively. ACE’s allocated share was $5 million and $6 million, respectively, for the three months ended March 31, 2013 and 2012.

In the first quarter of 2013, ACE made a discretionary tax-deductible contribution to the PHI Retirement Plan of $30 million. In the first quarter of 2012, ACE made a discretionary tax-deductible contribution to the PHI Retirement Plan of $30 million.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2013	Apr. 24, 2013
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1
Trading Symbol	POM
Entity Registrant Name	PEPCO HOLDINGS INC
Entity Central Index Key	0001135971
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		248,581,877
Potomac Electric Power Co [Member]
Entity Information [Line Items]
Entity Registrant Name	POTOMAC ELECTRIC POWER CO
Entity Central Index Key	0000079732
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		100
Delmarva Power & Light Co/De [Member]
Entity Information [Line Items]
Entity Registrant Name	DELMARVA POWER & LIGHT CO /DE/
Entity Central Index Key	0000027879
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,000
Atlantic City Electric Co [Member]
Entity Information [Line Items]
Entity Registrant Name	ATLANTIC CITY ELECTRIC CO
Entity Central Index Key	0000008192
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		8,546,017

XML

Debt

3 Months Ended

Mar. 31, 2013

Debt

(10) DEBT

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement, which among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility.

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 is $750 million for PHI 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 the one month London Interbank Offered Rate 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 and other 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) with certain exceptions, a restriction on sales or other dispositions of assets, 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 credit agreement contains certain covenants and other customary agreements and requirements that, if not 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 covenants under this facility as of March 31, 2013.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

At March 31, 2013 and December 31, 2012, the amount of cash plus unused borrowing capacity under the credit facility available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $975 million and $861 million, respectively. PHI’s utility subsidiaries had combined cash and unused borrowing capacity under the credit facility of $635 million and $477 million at March 31, 2013 and December 31, 2012, respectively.

Commercial Paper

PHI, Pepco, DPL and ACE maintain on-going commercial paper programs to address short-term liquidity needs. As of March 31, 2013, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $250 million, respectively, subject to available borrowing capacity under the credit facility.

PHI, DPL and ACE had $408 million, $70 million and $185 million, respectively, of commercial paper outstanding at March 31, 2013. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during the three months ended March 31, 2013 was 0.76%, 0.38%, 0.36% and 0.37%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during the three months ended March 31, 2013 was ten, seven, three and seven days, respectively.

Other Financing Activities

Term Loan Agreement

On March 28, 2013, PHI entered into a $250 million term loan agreement, pursuant to which PHI has borrowed (and may not re-borrow) $250 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the London Interbank Offered Rate (LIBOR) with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.875%. PHI’s Eurodollar borrowings under the loan agreement may be converted into floating rate loans under certain circumstances, and, in that event, for so long as any loan remains a floating rate loan, interest would accrue on that loan at a rate per year equal to (i) the highest of (a) the prevailing prime rate, (b) the federal funds effective rate plus 0.5%, or (c) the one-month Eurodollar rate plus 1%, plus (ii) a margin of 0.875%. As of March 31, 2013, outstanding borrowings under the loan agreement bore interest at an annual rate of 1.09%, which is subject to adjustment from time to time. All borrowings under the loan agreement are unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before March 27, 2014. PHI used the net proceeds of the loan under the loan agreement to repay the outstanding $200 million term loan made in 2012, and for general corporate purposes.

Under the terms of the term loan agreement, PHI must maintain compliance with specified covenants, including (i) the requirement that PHI maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the loan 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 permitted sales and dispositions, and (iii) a restriction on the incurrence of liens (other than liens permitted by the loan agreement) on the assets of PHI or any of its significant subsidiaries. The loan agreement does not include any rating triggers. PHI was in compliance with all covenants under this agreement as of March 31, 2013.

Bond Issuances

In March 2013, Pepco issued $250 million of 4.15% first mortgage bonds due March 15, 2043. These bonds were issued under a Mortgage and Deed of Trust and are secured thereunder by a first lien, subject to certain leases, permitted liens and other exceptions, on substantially all of Pepco’s properties. Net proceeds from the issuance of the long-term debt were used to repay Pepco’s outstanding commercial paper that was issued to temporarily fund capital expenditures, provide working capital and for general corporate purposes.

Bond Payments

In January 2013, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

Financing Activities Subsequent to March 31, 2013

Bond Payments

In April 2013, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

Bond Redemptions

In April 2013, ACE issued notice for optional redemption on May 30, 2013, at par plus accrued interest, of all $4.4 million outstanding weekly rate pollution control revenue refunding bonds due 2017, issued by the Pollution Control Financing Authority of Salem County, New Jersey for ACE’s benefit.

Collateral Requirements of Pepco Energy Services

In the ordinary course of its energy supply business, which is in the process of being wound down, Pepco Energy Services entered 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.

As of March 31, 2013, Pepco Energy Services had posted net cash collateral of $5 million and letters of credit of less than $1 million associated with its retail electric supply business. At December 31, 2012, Pepco Energy Services had posted net cash collateral of $14 million and letters of credit of less than $1 million associated with its retail electric supply business.

At March 31, 2013 and December 31, 2012, the amount of cash, plus borrowing capacity under PHI’s credit facility available to meet the future liquidity needs of Pepco Energy Services, totaled $340 million and $384 million, respectively.

Potomac Electric Power Co [Member]

Debt

(8) DEBT

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement, which among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility.

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 is $750 million for PHI 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 the one month London Interbank Offered Rate 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 and other 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) with certain exceptions, a restriction on sales or other dispositions of assets, 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 credit agreement contains certain covenants and other customary agreements and requirements that, if not 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 covenants under this facility as of March 31, 2013.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

At March 31, 2013 and December 31, 2012, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $635 million and $477 million, respectively. Pepco’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by DPL and ACE and the portion of the total capacity being used by PHI.

Commercial Paper

Pepco maintains an on-going commercial paper program to address its short-term liquidity needs. As of March 31, 2013, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

Pepco had no commercial paper outstanding at March 31, 2013. The weighted average interest rate for commercial paper issued by Pepco during the three months ended March 31, 2013 was 0.38% and the weighted average maturity of all commercial paper issued by Pepco during the three months ended March 31, 2013 was seven days.

Other Financing Activities

In March 2013, Pepco issued $250 million of 4.15% first mortgage bonds due March 15, 2043. These bonds were issued under a Mortgage and Deed of Trust and are secured thereunder by a first lien, subject to certain leases, permitted liens and other exceptions, on substantially all of Pepco’s properties. Net proceeds from the issuance of the long-term debt were used to repay Pepco’s outstanding commercial paper that was issued to temporarily fund capital expenditures, provide working capital and for general corporate purposes.

Delmarva Power & Light Co/De [Member]

Debt

(9) DEBT

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement, which among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility.

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 is $750 million for PHI 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 or 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 the one month London Interbank Offered Rate 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 and other 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) with certain exceptions, a restriction on sales or other dispositions of assets, 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 credit agreement contains certain covenants and other customary agreements and requirements that, if not 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 covenants under this facility as of March 31, 2013.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

At March 31, 2013 and December 31, 2012, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $635 million and $477 million, respectively. DPL’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and ACE and the portion of the total capacity being used by PHI.

Commercial Paper

DPL maintains an on-going commercial paper program to address its short-term liquidity needs. As of March 31, 2013, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

DPL had $70 million of commercial paper outstanding at March 31, 2013. The weighted average interest rate for commercial paper issued by DPL during the three months ended March 31, 2013 was 0.36% and the weighted average maturity of all commercial paper issued by DPL during the three months ended March 31, 2013 was three days.

Atlantic City Electric Co [Member]

Debt

(8) DEBT

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement, which among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility.

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 is $750 million for PHI 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 or 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 the one month London Interbank Offered Rate 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 and other 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) with certain exceptions, a restriction on sales or other dispositions of assets, 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 credit agreement contains certain covenants and other customary agreements and requirements that, if not 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 covenants under this facility at March 31, 2013.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

At March 31, 2013 and December 31, 2012, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $635 million and $477 million, respectively. ACE’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and DPL and the portion of the total capacity being used by PHI.

Commercial Paper

ACE maintains an on-going commercial paper program to address its short-term liquidity needs. As of March 31, 2013, the maximum capacity available under the program was $250 million, subject to available borrowing capacity under the credit facility.

ACE had $185 million of commercial paper outstanding at March 31, 2013. The weighted average interest rate for commercial paper issued by ACE during the three months ended March 31, 2013 was 0.37% and the weighted average maturity of all commercial paper issued by ACE during the three months ended March 31, 2013 was seven days.

Financing Activities

Bond Payments

In January 2013, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

Financing Activities Subsequent to March 31, 2013

Bond Payments

In April 2013, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-2.

Bond Redemptions

In April 2013, ACE issued notice for optional redemption on May 30, 2013, at par plus accrued interest, of all $4.4 million outstanding weekly rate pollution control revenue refunding bonds due 2017, issued by the Pollution Control Financing Authority of Salem County, New Jersey for ACE’s benefit.

XML

Discontinued Operations (Fair Value Of Derivative Instruments By Balance Sheet Location) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Derivative [Line Items]
Derivative liabilities (current liabilities)	$ (2)		$ (7)
Derivative liabilities (non-current liabilities)	(11)		(11)
Derivatives Designated As Hedging Instruments [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	(2)	[1]	(5)	[1]
Net Derivative (liability) asset	(2)	[1]	(5)	[1]
Other Derivative Instruments [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	(2)		(8)
Derivative liabilities (non-current liabilities)	(11)		(11)
Net Derivative (liability) asset	(13)		(19)
Gross Derivative Instruments [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	(4)		(13)
Derivative liabilities (non-current liabilities)	(11)		(11)
Net Derivative (liability) asset	(15)		(24)
Effects Of Cash Collateral And Netting [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	2		6
Net Derivative (liability) asset	2		6
Net Derivative Instruments [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	(2)		(7)
Derivative liabilities (non-current liabilities)	(11)		(11)
Net Derivative (liability) asset	(13)		(18)
Discontinued Operations [Member]
Derivative [Line Items]
Net Derivative (liability) asset	(8)		(12)
Discontinued Operations [Member] | Derivatives Designated As Hedging Instruments [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)			(5)	[1]
Derivative liabilities (non-current liabilities)			(1)	[1]
Net Derivative (liability) asset			(6)	[1]
Discontinued Operations [Member] | Other Derivative Instruments [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	(7)		(5)
Derivative liabilities (non-current liabilities)	(1)		(1)
Net Derivative (liability) asset	(8)		(6)
Discontinued Operations [Member] | Gross Derivative Instruments [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	(7)		(10)
Derivative liabilities (non-current liabilities)	(1)		(2)
Net Derivative (liability) asset	(8)		(12)
Discontinued Operations [Member] | Effects Of Cash Collateral And Netting [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	7		10
Derivative liabilities (non-current liabilities)	1		2
Net Derivative (liability) asset	8		12
Discontinued Operations [Member] | Net Derivative Instruments [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)
Derivative liabilities (non-current liabilities)
Net Derivative (liability) asset

[1] Amounts included in Derivatives Designated as Hedging Instruments primarily consist of derivatives that were designated as cash flow hedges prior to Pepco Energy Services' election to discontinue cash flow hedge accounting for these derivatives.

XML

Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
CURRENT ASSETS
Cash and cash equivalents	$ 125	$ 25
Restricted cash equivalents	10	10
Accounts receivable, less allowance for uncollectible accounts	838	837
Inventories	153	155
Derivative assets		1
Prepayments of income taxes	50	59
Deferred income tax assets, net	36	28
Income taxes receivable	243	69
Prepaid expenses and other	66	76
Assets held for sale		1
Total Current Assets	1,521	1,261
INVESTMENTS AND OTHER ASSETS
Goodwill	1,407	1,407
Regulatory assets	2,566	2,614
Investment in finance leases held in trust	869	1,237
Income taxes receivable	51	217
Restricted cash equivalents	16	17
Assets and accrued interest related to uncertain tax positions	9	18
Derivative assets	8	8
Other	174	163
Total Investments and Other Assets	5,100	5,681
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	13,830	13,625
Accumulated depreciation	(4,796)	(4,779)
Net Property, Plant and Equipment	9,034	8,846
TOTAL ASSETS	15,655	15,788
CURRENT LIABILITIES
Short-term debt	1,041	965
Current portion of long-term debt and project funding	569	569
Accounts payable and accrued liabilities	486	574
Capital lease obligations due within one year	9	8
Taxes accrued	50	75
Interest accrued	84	47
Liabilities and accrued interest related to uncertain tax positions	379	9
Derivative liabilities	2	7
Other	256	273
Liabilities associated with assets held for sale	7	10
Total Current Liabilities	2,883	2,537
DEFERRED CREDITS
Regulatory liabilities	492	501
Deferred income taxes, net	2,685	3,176
Investment tax credits	20	20
Pension benefit obligation	388	449
Other postretirement benefit obligations	451	454
Liabilities and accrued interest related to uncertain tax positions	27	15
Derivative liabilities	11	11
Other	195	191
Liabilities associated with assets held for sale	1	2
Total Deferred Credits	4,270	4,819
LONG-TERM LIABILITIES
Long-term debt	3,898	3,648
Transition bonds issued by ACE Funding	246	256
Long-term project funding	11	12
Capital lease obligations	69	70
Total Long-Term Liabilities	4,224	3,986
COMMITMENTS AND CONTINGENCIES
EQUITY
Common stock	2	2
Premium on stock and other capital contributions	3,706	3,383
Accumulated other comprehensive loss	(42)	(48)
Retained earnings	612	1,109
Total Equity	4,278	4,446
TOTAL LIABILITIES AND EQUITY	15,655	15,788
Potomac Electric Power Co [Member]
CURRENT ASSETS
Cash and cash equivalents	97	9
Accounts receivable, less allowance for uncollectible accounts	321	318
Inventories	71	69
Prepayments of income taxes	9	9
Income taxes receivable	120	31
Prepaid expenses and other	23	25
Total Current Assets	641	461
INVESTMENTS AND OTHER ASSETS
Regulatory assets	493	487
Prepaid pension expense	349	353
Investment in trust	31	31
Income taxes receivable	18	102
Other	63	59
Total Investments and Other Assets	954	1,032
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	6,939	6,850
Accumulated depreciation	(2,704)	(2,705)
Net Property, Plant and Equipment	4,235	4,145
TOTAL ASSETS	5,830	5,638
CURRENT LIABILITIES
Short-term debt		231
Current portion of long-term debt and project funding	200	200
Accounts payable and accrued liabilities	175	214
Accounts payable due to associated companies	49	41
Capital lease obligations due within one year	9	8
Taxes accrued	22	58
Interest accrued	39	17
Liabilities and accrued interest related to uncertain tax positions	24
Other	110	106
Total Current Liabilities	628	875
DEFERRED CREDITS
Regulatory liabilities	145	141
Deferred income taxes, net	1,249	1,219
Investment tax credits	3	4
Other postretirement benefit obligations	66	66
Liabilities and accrued interest related to uncertain tax positions	10	53
Other	68	66
Total Deferred Credits	1,541	1,549
LONG-TERM LIABILITIES
Long-term debt	1,751	1,501
Capital lease obligations	69	70
Total Long-Term Liabilities	1,820	1,571
COMMITMENTS AND CONTINGENCIES
EQUITY
Common stock
Premium on stock and other capital contributions	930	755
Retained earnings	911	888
Total Equity	1,841	1,643
TOTAL LIABILITIES AND EQUITY	5,830	5,638
Delmarva Power & Light Co/De [Member]
CURRENT ASSETS
Cash and cash equivalents	10	6
Accounts receivable, less allowance for uncollectible accounts	216	201
Inventories	48	53
Prepayments of income taxes	10	10
Income taxes receivable	6	10
Assets and accrued interest related to uncertain tax positions	17
Prepaid expenses and other	19	20
Total Current Assets	326	300
INVESTMENTS AND OTHER ASSETS
Goodwill	8	8
Regulatory assets	276	288
Prepaid pension expense	239	232
Assets and accrued interest related to uncertain tax positions	3	20
Other	12	12
Total Investments and Other Assets	538	560
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	3,479	3,422
Accumulated depreciation	(1,002)	(1,000)
Net Property, Plant and Equipment	2,477	2,422
TOTAL ASSETS	3,341	3,282
CURRENT LIABILITIES
Short-term debt	175	137
Current portion of long-term debt and project funding	250	250
Accounts payable and accrued liabilities	100	125
Accounts payable due to associated companies	22	20
Taxes accrued	5	4
Interest accrued	15	6
Derivative liabilities		4
Other	61	61
Total Current Liabilities	628	607
DEFERRED CREDITS
Regulatory liabilities	258	258
Deferred income taxes, net	716	697
Investment tax credits	5	5
Other postretirement benefit obligations	22	22
Other	34	41
Total Deferred Credits	1,035	1,023
LONG-TERM LIABILITIES
Long-term debt	667	667
COMMITMENTS AND CONTINGENCIES
EQUITY
Common stock
Premium on stock and other capital contributions	407	407
Retained earnings	604	578
Total Equity	1,011	985
TOTAL LIABILITIES AND EQUITY	3,341	3,282
Atlantic City Electric Co [Member]
CURRENT ASSETS
Cash and cash equivalents	10	6
Restricted cash equivalents	10	10
Accounts receivable, less allowance for uncollectible accounts	191	192
Inventories	30	30
Prepayments of income taxes	27	27
Income taxes receivable	112	5
Assets and accrued interest related to uncertain tax positions	10
Prepaid expenses and other	9	11
Total Current Assets	399	281
INVESTMENTS AND OTHER ASSETS
Regulatory assets	670	694
Prepaid pension expense	115	88
Income taxes receivable	31	133
Restricted cash equivalents	16	17
Assets and accrued interest related to uncertain tax positions	6	12
Derivative assets	8	8
Other	11	12
Total Investments and Other Assets	857	964
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	2,820	2,771
Accumulated depreciation	(794)	(787)
Net Property, Plant and Equipment	2,026	1,984
TOTAL ASSETS	3,282	3,229
CURRENT LIABILITIES
Short-term debt	208	133
Current portion of long-term debt and project funding	108	108
Accounts payable and accrued liabilities	122	147
Accounts payable due to associated companies	17	14
Taxes accrued	20	10
Interest accrued	20	15
Other	44	47
Total Current Liabilities	539	474
DEFERRED CREDITS
Regulatory liabilities	89	102
Deferred income taxes, net	769	766
Investment tax credits	6	6
Other postretirement benefit obligations	34	34
Derivative liabilities	11	11
Other	17	18
Total Deferred Credits	926	937
LONG-TERM LIABILITIES
Long-term debt	760	760
Transition bonds issued by ACE Funding	246	256
Total Long-Term Liabilities	1,006	1,016
COMMITMENTS AND CONTINGENCIES
EQUITY
Common stock	26	26
Premium on stock and other capital contributions	576	576
Retained earnings	209	200
Total Equity	811	802
TOTAL LIABILITIES AND EQUITY	$ 3,282	$ 3,229

XML

Recently Issued Accounting Standards, Not Yet Adopted

3 Months Ended

Mar. 31, 2013

Recently Issued Accounting Standards, Not Yet Adopted

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Joint and Several Liability Arrangements (ASC 405)

In February 2013, the FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, PHI will be required to include in its liabilities the additional amounts it expects to pay on behalf of its co-obligors, if any. PHI will also be required to provide additional disclosures including the nature of the arrangements with its co-obligors, the total amounts outstanding under the arrangements between PHI and its co-obligors, the carrying value of the liability, and the nature and limitations of any recourse provisions that would enable recovery from other entities.

The new requirements would be effective retroactively beginning on January 1, 2014, with implementation required for prior periods if joint and several liability arrangement obligations exist as of January 1, 2014. PHI is evaluating the impact of this new guidance on its consolidated financial statements.

Potomac Electric Power Co [Member]

Recently Issued Accounting Standards, Not Yet Adopted

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Joint and Several Liability Arrangements (Accounting Standards Codification (ASC) 405)

In February 2013, the Financial Accounting Standards Board (FASB) issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, Pepco will be required to include in its liabilities the additional amounts it expects to pay on behalf of its co-obligors, if any. Pepco will also be required to provide additional disclosures including the nature of the arrangements with its co-obligors, the total amounts outstanding under the arrangements between Pepco and its co-obligors, the carrying value of the liability, and the nature and limitations of any recourse provisions that would enable recovery from other entities.

The new requirements would be effective retroactively beginning on January 1, 2014, with implementation required for prior periods if joint and several liability arrangement obligations exist as of January 1, 2014. Pepco is evaluating the impact of this new guidance on its financial statements.

Delmarva Power & Light Co/De [Member]

Recently Issued Accounting Standards, Not Yet Adopted

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Joint and Several Liability Arrangements (ASC 405)

In February 2013, the FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, DPL will be required to include in its liabilities the additional amounts it expects to pay on behalf of its co-obligors, if any. DPL will also be required to provide additional disclosures including the nature of the arrangements with its co-obligors, the total amounts outstanding under the arrangements between DPL and its co-obligors, the carrying value of the liability, and the nature and limitations of any recourse provisions that would enable recovery from other entities.

The new requirements would be effective retroactively beginning on January 1, 2014, with implementation required for prior periods if joint and several liability arrangement obligations exist as of January 1, 2014. DPL is evaluating the impact of this new guidance on its financial statements.

Atlantic City Electric Co [Member]

Recently Issued Accounting Standards, Not Yet Adopted

(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED

Joint and Several Liability Arrangements (ASC 405)

In February 2013, the FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, ACE will be required to include in its liabilities the additional amounts it expects to pay on behalf of its co-obligors, if any. ACE will also be required to provide additional disclosures including the nature of the arrangements with its co-obligors, the total amounts outstanding under the arrangements between ACE and its co-obligors, the carrying value of the liability, and the nature and limitations of any recourse provisions that would enable recovery from other entities.

The new requirements would be effective retroactively beginning on January 1, 2014, with implementation required for prior periods if joint and several liability arrangement obligations exist as of January 1, 2014. ACE is evaluating the impact of this new guidance on its consolidated financial statements.

XML

Newly Adopted Accounting Standards

3 Months Ended

Mar. 31, 2013

Newly Adopted Accounting Standards

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Balance Sheet (ASC 210)

In December 2011, the FASB issued new disclosure requirements for financial assets and financial liabilities, such as derivatives, that are subject to contractual netting arrangements. The new disclosure requirements include information about the gross exposure of the instruments and the net exposure of the instruments under contractual netting arrangements, how the exposures are presented in the financial statements, and the terms and conditions of the contractual netting arrangements. As of March 31, 2013, PHI adopted the new guidance and concluded it did not have a material impact on its consolidated financial statements.

Comprehensive Income (ASC 220)

The new disclosure requirements for reclassifications from accumulated other comprehensive income were effective for PHI beginning with its March 31, 2013 consolidated financial statements and required PHI to present additional information about its reclassifications from accumulated other comprehensive income in a single footnote or on the face of its consolidated financial statements. The additional information required to be disclosed includes a presentation of the components of accumulated other comprehensive income that have been reclassified by source (e.g., commodity derivatives), and the income statement line item (e.g., Fuel and Purchased Energy) affected by the reclassification. PHI has provided the new required disclosures in Note (16), “Accumulated Other Comprehensive Loss.”

Potomac Electric Power Co [Member]

Newly Adopted Accounting Standards

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

None.

Delmarva Power & Light Co/De [Member]

Newly Adopted Accounting Standards

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Balance Sheet (Accounting Standards Codification (ASC) 210)

In December 2011, the FASB issued new disclosure requirements for financial assets and financial liabilities, such as derivatives, that are subject to contractual netting arrangements. The new disclosure requirements include information about the gross exposure of the instruments and the net exposure of the instruments under contractual netting arrangements, how the exposures are presented in the financial statements, and the terms and conditions of the contractual netting arrangements. As of March 31, 2013, DPL adopted the new guidance and concluded it did not have a material impact on its financial statements.

Atlantic City Electric Co [Member]

Newly Adopted Accounting Standards

(3) NEWLY ADOPTED ACCOUNTING STANDARDS

Balance Sheet (ASC 210)

In December 2011, the FASB issued new disclosure requirements for financial assets and financial liabilities, such as derivatives, that are subject to contractual netting arrangements. The new disclosure requirements include information about the gross exposure of the instruments and the net exposure of the instruments under contractual netting arrangements, how the exposures are presented in the financial statements, and the terms and conditions of the contractual netting arrangements. As of March 31, 2013, ACE adopted the new guidance and concluded it did not have a material impact on its consolidated financial statements.

XML

Commitments And Contingencies

3 Months Ended

Mar. 31, 2013

Commitments And Contingencies

(15) COMMITMENTS AND CONTINGENCIES

General Litigation and Other Matters

In September 2011, an asbestos complaint was filed in the New Jersey Superior Court, Law Division, against ACE (among other defendants) asserting claims under New Jersey’s Wrongful Death and Survival statutes. The complaint, filed by the estate of a decedent who was the wife of a former employee of ACE, alleges that the decedent’s mesothelioma was caused by exposure to asbestos brought home by her husband on his work clothes. New Jersey courts have recognized a cause of action against a premise owner in a so-called “take home” case if it can be shown that the harm was foreseeable. In this case, the complaint seeks recovery of an unspecified amount of damages for, among other things, the decedent’s past medical expenses, loss of earnings, and pain and suffering between the time of injury and death, and asserts a punitive damage claim. At this time, ACE has concluded that a loss is reasonably possible with respect to this matter, but ACE was unable to estimate an amount or range of reasonably possible loss because (i) the damages sought are indeterminate, (ii) the proceedings are in the early stages, and (iii) the matter involves facts that ACE believes are distinguishable from the facts of the “take-home” cause of action recognized by the New Jersey courts. A trial date has been set for May 20, 2013.

During 2012, Pepco Energy Services received letters on behalf of two school districts in Maryland, which claim that invoices in connection with electricity supply contracts contained certain allegedly unauthorized charges, totaling approximately $7 million. The school districts also claim additional compounded interest totaling approximately $9 million. Pepco Energy Services disputes both the allegations regarding unauthorized charges and the claims of entitlement to compounded interest in their entirety, and has been in discussions with the school districts to attempt to resolve these claims. No litigation involving Pepco Energy Services related to these claims has commenced. As of March 31, 2013, the amount of loss that may be associated with these claims is not reasonably estimable, and Pepco Energy Services cannot estimate an amount or range of reasonably possible loss associated with the claims.

Environmental Matters

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 PHI’s utility subsidiaries, environmental clean-up costs incurred by Pepco, DPL and ACE generally are included by each company in its respective cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies described below of PHI and its subsidiaries at March 31, 2013 are summarized as follows:

			Legacy Generation
	Transmission and  Distribution		Regulated		Non- Regulated		Other		Total
	(millions of dollars)
Beginning balance as of January 1	$	15	$	7	$	5	$	2	$	29
Accruals		—		—		—		—		—
Payments		—		1		—		—		1
Ending balance as of March 31		15		6		5		2		28
Less amounts in Other current liabilities		2		1		—		2		5
Amounts in Other deferred credits	$	13	$	5	$	5	$	—	$	23

Conectiv Energy Wholesale Power Generation Sites

In July 2010, PHI sold the Conectiv Energy wholesale power generation business to Calpine Corporation (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. The amount accrued by PHI for the ISRA-required remediation activities at the nine generating facility sites is included in the table above in the column entitled “Legacy Generation – Non-Regulated.”

In September 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 February 2004 and July 1, 2010, to demonstrate compliance with the Clean Air Act’s new source review permitting program. PHI responded to the data request. 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 adverse effect on its consolidated financial condition, results of operations or cash flows.

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’s feasibility study for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million.

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. The National Priorities List, 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 September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with the RI/FS, any remediation activities to be performed at the site or any other 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 ACE, DPL and Pepco, based on their alleged sale of transformers to Ward Transformer, 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. The litigation is moving forward with certain “test case” defendants (not including ACE, DPL and Pepco) filing summary judgment motions regarding liability. The case has been stayed as to the

remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The district court’s order addresses only the liability of the test case defendant. PHI has concluded that a loss is reasonably possible with respect to this matter, but PHI was unable to estimate an amount or range of reasonably possible losses to which it may be exposed. PHI does not believe that any of its three utility subsidiaries had extensive business transactions, if any, with the Ward Transformer site.

Benning Road Site

In September 2010, PHI received a letter from EPA identifying the Benning Road location, consisting of a generation facility operated by Pepco Energy Services until the facility was deactivated in June 2012, and a transmission and distribution facility operated by Pepco, 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. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the District of Columbia Department of the Environment (DDOE), which 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. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DDOE will look to the companies to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. The court order entering the consent decree requires the parties to submit a written status report to the court on May 24, 2013 regarding the implementation of the requirements of the consent decree and any related plans for remediation. In addition, if the RI/FS has not been completed by May 24, 2013, the status report must provide an explanation and a showing of good cause for why the work has not been completed.

Pepco and Pepco Energy Services submitted a proposed RI/FS work plan in July 2012, and filed a revised work plan in December 2012 based on comments from DDOE and the public. DDOE approved the revised work plan on December 28, 2012; RI/FS field work commenced in January 2013 and is still in progress.

The remediation costs accrued for this matter are included in the table above in the columns entitled “Transmission and Distribution,” “Legacy Generation – Regulated,” and “Legacy Generation – Non-Regulated.”

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. The amount of remediation costs accrued for this matter is included in the table above in the column entitled “Legacy Generation – Regulated.”

Potomac River Mineral Oil Release

In January 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.

Beginning in March 2011, DDOE issued a series of compliance directives requiring 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 completed field sampling during the fourth quarter of 2011 and submitted sampling results to DDOE during the second quarter of 2012. Pepco is continuing discussions with DDOE regarding the need for any further response actions but expects that additional monitoring of shoreline sediments may be required.

In June 2012, Pepco commenced discussions with DDOE regarding a possible consent decree that would resolve DDOE’s threatened claims for civil penalties for alleged violation of the District’s Water Pollution Control Law, as well as for damages to natural resources. Pepco and DDOE have reached an agreement in principle that would consist of a combination of a civil penalty and Supplemental Environmental Projects (SEPs) with a total cost to Pepco of approximately $1 million. Discussions with DDOE continue regarding the specific nature and scope of the SEPs, as well as the amount of DDOE’s and the federal resource trustees’ natural resource damage claim. This matter is expected to be resolved through the entry of a consent decree sometime in 2013. Based on discussions to date, PHI and Pepco do not believe that the resolution of these claims will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

As a result of the oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility which involve pumping accumulated storm water to an aboveground holding tank for off-site disposal. In December 2011, Pepco completed the installation of a treatment system designed to allow automatic discharge of accumulated storm water from the secondary containment system. Pepco currently is seeking DDOE’s and EPA’s approval to commence operation of the new system. In the meantime, Pepco is continuing to use the aboveground holding tank to manage storm water from the secondary containment system.

The amounts accrued for these matters are included in the table above in the column entitled “Transmission and Distribution.”

Metal Bank Site

In January 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco (and contacted DPL in March 2013) on behalf of itself and other federal and state trustees to request that Pepco and DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Superfund Site located in Philadelphia, Pennsylvania. Pepco and DPL have executed the tolling agreement and will participate in settlement discussions with the NOAA, the trustees and other PRPs. While a loss associated with this matter is reasonably possible for Pepco and DPL, an estimate of the amount or range of reasonably possible loss cannot be made at this time because the matter is in its early stages and discussions with the NOAA and other parties have yet to commence; however, costs to resolve this matter are not expected to be material for Pepco and DPL in the aggregate.

PHI’s Cross-Border Energy Lease Investments

As discussed in Note (8), “Leasing Activities,” PHI has a portfolio of cross-border energy lease investments involving public utility assets located outside of the United States with a net investment value of approximately $869 million as of March 31, 2013. Each of these investments is comprised of multiple leases and each investment is structured as a sale and leaseback transaction commonly referred to by the IRS as a sale-in, lease-out, or SILO, transaction.

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 income tax returns, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI for six of the eight lease investments and, in connection with the audits of PHI’s 2003-2005 and 2006-2008 income tax returns, the IRS disallowed such deductions in excess of rental income for all eight of the lease investments. In addition, the IRS has sought to recharacterize each of the leases as a loan transaction in each of the years under audit as to which PHI would be subject to original issue discount income. PHI has disagreed with the IRS’ proposed adjustments to the 2001-2008 income tax returns and has filed protests of these findings for each year with the Office of Appeals of the IRS. In November 2010, PHI entered into a settlement agreement with the IRS for the 2001 and 2002 tax years solely for the purpose of commencing litigation associated with this matter and subsequently filed refund claims in July 2011 for the disallowed tax deductions relating to the

leases for these years. In January 2011, 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. Since the July 2011 refund claims were not approved by the IRS within the statutory six-month period, in January 2012 PHI filed complaints in the U.S. Court of Federal Claims seeking recovery of the tax payment, interest and penalties. The 2003-2005 and 2006-2011 income tax return audits continue to be in process with the IRS Office of Appeals and the IRS Exam Division, respectively, and are not presently a part of the U.S. Court of Federal Claims litigation discussed above.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. While PHI believes that its tax position with regard to its cross-border energy lease investments is appropriate, after analyzing the recent U.S. Court of Appeals ruling, PHI has determined that its tax position with respect to the tax benefits associated with the cross-border energy leases no longer meets the more likely than not standard of recognition for accounting purposes. Accordingly, PHI recorded a non-cash charge of $377 million (after-tax) in the first quarter of 2013 (as discussed in Note (8), “Leasing Activities”), consisting of a charge to reduce the carrying value of the cross-border energy lease investments and a charge to reflect the anticipated additional interest expense related to changes in PHI’s estimated federal and state income tax obligations for the period over which the tax benefits ultimately may be disallowed. PHI had also previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. Management believes that it can no longer support its conclusions regarding these business assumptions, and the effects of this change in conclusion are included in the charge. While the IRS could require PHI to pay a penalty of up to 20% of the amount of additional taxes due, PHI believes that it is more likely than not that no such penalty will be incurred, and therefore no amount for any potential penalty was included in the charge recorded in the first quarter of 2013.

In the event that the IRS were to be successful in disallowing 100% of the tax benefits associated with these lease investments and recharacterizing these lease investments as loans, PHI estimated that, as of March 31, 2013, it would have been obligated to pay approximately $192 million in additional federal taxes (net of the $74 million tax payment described above) and approximately $50 million of interest on the additional federal taxes. These amounts, totaling $242 million, were estimated after consideration of certain tax benefits arising from matters unrelated to the leases that would offset the taxes and interest due, including PHI’s best estimate of the expected resolution of other uncertain and effectively settled tax positions, the carrying back and carrying forward of any existing net operating losses, and the application of certain amounts on deposit with the IRS. In order to mitigate PHI’s ongoing interest costs associated with the $242 million estimate of additional taxes and interest, PHI made a deposit with the IRS of $242 million in the first quarter of 2013. This deposit was funded from currently available sources of liquidity and short-term borrowings. PHI anticipates that any liquidation proceeds from lease terminations as described in Note (8), “Leasing Activities,” could be used to repay short-term borrowings utilized to fund the deposit.

PHI continues to weigh its options with respect to its litigation with the IRS. Pursuant to an agreement reached by the parties before the judge in January 2013, further discovery in the case is effectively stayed until July 1, 2013. The current schedule for the case requires that discovery be concluded by December 31, 2013, with a likely trial date in the second half of 2014.

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

PHI 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 March 31, 2013, PHI and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, energy procurement obligations, and other commitments and obligations. The commitments and obligations, in millions of dollars, were as follows:

	Guarantor
	PHI		Pepco		DPL		ACE		Total
Energy procurement obligations of Pepco Energy Services (a)	$	75	$	—	$	—	$	—	$	75
Guarantees associated with disposal of Conectiv Energy assets (b)		13		—		—		—		13
Guaranteed lease residual values (c)		2		5		7		4		18
Total	$	90	$	5	$	7	$	4	$	106

(a) PHI 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 of Conectiv Energy’s derivatives portfolio transferred in connection with the disposition of Conectiv Energy’s wholesale business. 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) Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $55 million, $8 million of which is a guaranty by PHI, $15 million by Pepco, $19 million by DPL and $13 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

PHI 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 Services Performance Contracts

Pepco Energy Services has a diverse portfolio of energy savings services performance contracts that are associated with the installation of energy savings equipment or combined heat and power facilities for federal, state and local government customers. As part of the energy savings contracts, Pepco Energy Services typically guarantees that the equipment or systems it installs will generate a specified amount of energy savings on an annual basis over a multi-year period. As of March 31, 2013, the remaining notional amount of Pepco Energy Services’ energy savings guarantees on both completed projects and projects under construction totaled $441 million over the life of the multi-year performance contracts with the longest guarantee having a remaining term of 13 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.

As of March 31, 2013, Pepco Energy Services had a performance guarantee contract associated with the production at a combined heat and power facility that is under construction totaling $15 million in notional value over the life of the multi-year contracts, with the longest guarantee having a remaining term of 20 years.

Pepco Energy Services recognizes a liability for the value of the estimated energy savings or production shortfalls when it is probable that the guaranteed amounts will not be achieved and the amount is reasonably estimable. As of March 31, 2013, Pepco Energy Services had an accrued liability of $1 million for its energy savings or combined heat and power performance contracts that it established during 2012. There was no significant change in the type of contracts issued during the three months ended March 31, 2013 as compared to the three months ended March 31, 2012.

Dividends

On April 25, 2013, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable June 28, 2013, to stockholders of record on June 10, 2013.

Potomac Electric Power Co [Member]

Commitments And Contingencies

(11) COMMITMENTS AND CONTINGENCIES

Environmental Matters

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 customers of Pepco, environmental clean-up costs incurred by Pepco generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of Pepco described below at March 31, 2013 are summarized as follows:

	Transmission and Distribution		Legacy Generation - Regulated		Total
	(millions of dollars)
Beginning balance as of January 1	$	14	$	3	$	17
Accruals		—		—		—
Payments		—		—		—
Ending balance as of March 31		14		3		17
Less amounts in Other current liabilities		1		—		1
Amounts in Other deferred credits	$	13	$	3	$	16

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 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. The National Priorities List, 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 September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with the RI/FS, any remediation activities to be performed at the site or any other 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, based on its alleged sale of transformers to Ward Transformer, 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. The litigation is moving forward with certain “test case” defendants (not including Pepco) filing summary

judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The district court’s order addresses only the liability of the test case defendant. Pepco has concluded that a loss is reasonably possible with respect to this matter, but was unable to estimate an amount or range of reasonably possible losses to which it may be exposed. Pepco does not believe that it had extensive business transactions, if any, with the Ward Transformer site.

Benning Road Site

In September 2010, PHI received a letter from EPA identifying the Benning Road location, consisting of a generation facility operated by Pepco Energy Services and its subsidiaries (Pepco Energy Services) until the facility was deactivated in June 2012, and a transmission and distribution facility operated by Pepco, 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. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with District of Columbia Department of the Environment (DDOE), which 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. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DDOE will look to the companies to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. The court order entering the consent decree requires the parties to submit a written status report to the court on May 24, 2013 regarding the implementation of the requirements of the consent decree and any related plans for remediation. In addition, if the RI/FS has not been completed by May 24, 2013, the status report must provide an explanation and a showing of good cause for why the work has not been completed.

Pepco and Pepco Energy Services submitted a proposed RI/FS work plan in July 2012, and filed a revised work plan in December 2012 based on comments from DDOE and the public. DDOE approved the revised work plan on December 28, 2012; RI/FS field work commenced in January 2013 and is still in progress.

The remediation costs accrued for this matter are included in the table above in the columns entitled “Transmission and Distribution,” “Legacy Generation – Regulated,” and “Legacy Generation – Non-Regulated.”

Potomac River Mineral Oil Release

In January 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.

Beginning in March 2011, DDOE issued a series of compliance directives requiring 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 completed field sampling during the fourth quarter of 2011 and submitted sampling results to DDOE during the second quarter of 2012. Pepco is continuing discussions with DDOE regarding the need for any further response actions but expects that additional monitoring of shoreline sediments may be required.

In June 2012, Pepco commenced discussions with DDOE regarding a possible consent decree that would resolve DDOE’s threatened claims for civil penalties for alleged violation of the District’s Water Pollution Control Law, as well as for damages to natural resources. Pepco and DDOE have reached an agreement in principle that would consist of a combination of a civil penalty and Supplemental Environmental Projects (SEPs) with a total cost to Pepco of approximately $1 million. Discussions with DDOE continue regarding the specific nature and scope of the SEPs, as well as the amount of DDOE’s and the federal resource trustees’ natural resource damage claim. This matter is expected to be resolved through the entry of a consent decree sometime in 2013. Based on discussions to date, PHI and Pepco do not believe that the resolution of these claims will have a material adverse effect on their respective financial conditions, results of operations or cash flows.

As a result of the oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility which involve pumping accumulated storm water to an aboveground holding tank for off-site disposal. In December 2011, Pepco completed the installation of a treatment system designed to allow automatic discharge of accumulated storm water from the secondary containment system. Pepco currently is seeking DDOE’s and EPA’s approval to commence operation of the new system. In the meantime, Pepco is continuing to use the aboveground holding tank to manage storm water from the secondary containment system.

The amounts accrued for these matters are included in the table above in the column entitled “Transmission and Distribution.”

Metal Bank Site

In January 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco on behalf of itself and other federal and state trustees to request that Pepco execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Superfund Site located in Philadelphia, Pennsylvania. Pepco has executed the tolling agreement and will participate in settlement discussions with the NOAA, the trustees and other PRPs. While a loss associated with this matter is reasonably possible for Pepco, an estimate of the amount or range of reasonably possible loss cannot be made at this time because the matter is in its early stages and discussions with the NOAA and other parties have yet to commence; however, costs to resolve this matter are not expected to be material for Pepco.

Delmarva Power & Light Co/De [Member]

Commitments And Contingencies

(13) COMMITMENTS AND CONTINGENCIES

Environmental Matters

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 generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of DPL described below at March 31, 2013 are summarized as follows:

	Transmission and Distribution		Legacy Generation  - Regulated		Other		Total
	(millions of dollars)
Beginning balance as of January 1	$	1	$	3	$	2	$	6
Accruals		—		—		—		—
Payments		—		1		—		1
Ending balance as of March 31		1		2		2		5
Less amounts in Other Current Liabilities		1		1		2		4
Amounts in Other Deferred Credits	$	—	$	1	$	—	$	1

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, based on its alleged sale of transformers to Ward Transformer, 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. The litigation is moving forward with certain “test case” defendants (not including DPL) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The district court’s order addresses only the liability of the test case defendant. DPL has concluded that a loss is reasonably possible with respect to this matter, but was unable to estimate an amount or range of reasonably possible losses to which it may be exposed. DPL does not believe that it had extensive business transactions, if any, with the Ward Transformer site.

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.

The amount of remediation costs accrued for this matter is included in the table above in the column entitled “Legacy Generation – Regulated.”

Metal Bank Site

In March 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted DPL on behalf of itself and other federal and state trustees to request that DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Superfund Site located in Philadelphia, Pennsylvania. DPL has executed the tolling agreement and will participate in settlement discussions with the NOAA, the trustees and other PRPs. While a loss associated with this matter is reasonably possible for DPL, an estimate of the amount or range of reasonably possible loss cannot be made at this time because the matter is in its early stages and discussions with the NOAA and other parties have yet to commence; however, costs to resolve this matter are not expected to be material for DPL.

Atlantic City Electric Co [Member]

Commitments And Contingencies

(12) COMMITMENTS AND CONTINGENCIES

General Litigation

In September 2011, an asbestos complaint was filed in the New Jersey Superior Court, Law Division, against ACE (among other defendants) asserting claims under New Jersey’s Wrongful Death and Survival statutes. The complaint, filed by the estate of a decedent who was the wife of a former employee of ACE, alleges that the decedent’s mesothelioma was caused by exposure to asbestos brought home by her husband on his work clothes. New Jersey courts have recognized a cause of action against a premise owner in a so-called “take home” case if it can be shown that the harm was foreseeable. In this case, the complaint seeks recovery of an unspecified amount of damages for, among other things, the decedent’s past medical expenses, loss of earnings, and pain and suffering between the time of injury and death, and asserts a punitive damage claim. At this time, ACE has concluded that a loss is reasonably possible with respect to this matter, but ACE was unable to estimate an amount or range of reasonably possible loss because (i) the damages sought are indeterminate, (ii) the proceedings are in the early stages, and (iii) the matter involves facts that ACE believes are distinguishable from the facts of the “take-home” cause of action recognized by the New Jersey courts. A trial date has been set for May 20, 2013.

Environmental Matters

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 customers of ACE, environmental clean-up costs incurred by ACE generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of ACE described below at March 31, 2013 are summarized as follows:

	Legacy Generation - Regulated
	(millions of dollars)
Beginning balance as of January 1	$	1
Accruals		—
Payments		—
Ending balance as of March 31		1
Less amounts in Other Current Liabilities		—
Amounts in Other Deferred Credits	$	1

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’s feasibility study for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million.

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, based on its alleged sale of transformers to Ward Transformer, 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. The litigation is moving forward with certain “test case” defendants (not including ACE) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The district court’s order addresses only the liability of the test case defendant. ACE has concluded that a loss is reasonably possible with respect to this matter, but ACE was unable to estimate an amount or range of reasonably possible losses to which it may be exposed. ACE does not believe that it had extensive business transactions, if any, with the Ward Transformer site.

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Income Taxes

3 Months Ended

Mar. 31, 2013

Income Taxes

(11) INCOME TAXES

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

	Three Months Ended March 31,
	2013					2012
	(millions of dollars)
Income tax at Federal statutory rate	$	(103	)	35.0	%	$	26		35.0	%
Increases (decreases) resulting from:
State income taxes, net of Federal effect		5		(1.7	)%		4		5.4	%
Asset removal costs		(3	)	1.0	%		(3	)	(4.1	)%
Changes in estimates and interest related to uncertain and effectively settled tax positions		67		(22.7	)%		(13	)	(17.6	)%
Cross-border energy lease investments		64		(21.7	)%		(1	)	(1.4	)%
Establishment of valuation allowances related to deferred tax assets		101		(34.2	)%		—		—
Other, net		4		(1.5	)%		(2	)	(2.4	)%
Consolidated income tax expense related to continuing operations	$	135		(45.8	)%	$	11		14.9	%

PHI’s consolidated effective tax rates for the three months ended March 31, 2013 and 2012 were (45.8)% and 14.9%, respectively.

The negative effective tax rate in the first quarter of 2013 occurred as a result of recording $67 million of changes in estimates and interest related to uncertain and effectively settled tax positions, primarily associated with the cross-border energy lease investments (as further discussed in Note (8), “Leasing Activities”) and the recognition of a $64 million charge primarily for the tax consequences associated with PHI’s change in intent regarding foreign investment opportunities available at the end of the full lease terms of the cross-border energy lease investments.

The negative effective tax rate in the first quarter of 2013 further resulted from the establishment of valuation allowances of $101 million against certain deferred tax assets in PHI’s Other Non-Regulated segment. Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to both Consolidated Edison’s cross-border lease transaction (as discussed in Note (8), “Leasing Activities”) and another taxpayer’s structured transactions, (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represents a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI will be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI has established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013.

In 2012, PHI’s effective tax rate was impacted by the effective settlement with the IRS in the first quarter of 2012 with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position in Pepco.

Potomac Electric Power Co [Member]

Income Taxes

(9) INCOME TAXES

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

	Three Months Ended March 31,
	2013					2012
	(millions of dollars)
Income tax at Federal statutory rate	$	9		35.0	%	$	7		35.0	%
Increases (decreases) resulting from:
State income taxes, net of Federal effect		2		8.0	%		1		6.3	%
Asset removal costs		(3	)	(12.0	)%		(3	)	(15.8	)%
Changes in estimates and interest related to uncertain and effectively settled tax positions		(5	)	(20.0	)%		(10	)	(50.5	)%
Other, net		(1	)	(3.0	)%		—		(1.3	)%
Income tax expense (benefit)	$	2		8.0	%	$	(5	)	(26.3	)%

Pepco’s effective tax rates for the three months ended March 31, 2013 and 2012 and were 8.0% and (26.3)%, respectively. The increase in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which Pepco is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that it can no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded a charge of $377 million (after-tax) in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in Pepco recording a $5 million interest benefit in the first quarter of 2013.

In the first quarter of 2012, Pepco recorded benefits for changes in estimates and interest related to uncertain and effectively settled tax positions primarily due to the effective settlement with the Internal Revenue Service with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position.

Delmarva Power & Light Co/De [Member]

Income Taxes

(10) INCOME TAXES

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

	Three Months Ended March 31,
	2013					2012
	(millions of dollars)
Income tax at Federal statutory rate	$	15		35.0	%	$	12	35.0	%
Increases (decreases) resulting from:
State income taxes, net of Federal effect		2		4.7	%		2	5.7	%
Changes in estimates and interest related to uncertain and effectively settled tax positions		(1	)	(2.4	)%		—	—
Other, net		—		0.8	%		—	(0.7	)%
Income tax expense	$	16		38.1	%	$	14	40.0	%

DPL’s effective tax rates for the three months ended March 31, 2013 and 2012 were 38.1% and 40.0%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions. On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which DPL is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that it can no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded a charge of $377 million (after-tax) in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in DPL recording a $1 million interest benefit in the first quarter of 2013.

Atlantic City Electric Co [Member]

Income Taxes

(9) INCOME TAXES

ACE’s consolidated effective tax rates for the three months ended March 31, 2013 and 2012 were (50.3)% and (100)%, respectively. The change in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions. In the first quarter of 2013, ACE recorded an interest benefit of $6 million as discussed further below. In the first quarter of 2012, ACE recorded an interest benefit as a result of the effective settlement with the Internal Revenue Service with respect to the methodology used historically to calculate deductible mixed service costs.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which ACE is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that it can no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded a charge of $377 million (after-tax) in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in ACE recording a $6 million interest benefit in the first quarter of 2013.

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Discontinued Operations (Schedule Of Derivative Gain (Loss) Amounts Recognized In Income) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Pepco Energy Services [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Reclassification of mark-to-market to realized on settlement of contracts	$ 2	$ 2
Unrealized mark-to-market loss		(4)
Total net (loss) gain	2	(2)
Discontinued Operations [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized mark-to-market loss	(4)
Discontinued Operations [Member] | Pepco Energy Services [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Reclassification of mark-to-market to realized on settlement of contracts	2	8
Unrealized mark-to-market loss	(3)	(6)
Total net (loss) gain	$ (1)	$ 2

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Regulatory Matters

3 Months Ended

Mar. 31, 2013

Regulatory Matters

(7) REGULATORY MATTERS

Rate Proceedings

Over the last several years, PHI’s utility subsidiaries have proposed in each of their respective jurisdictions 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) was approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia.

• A modified fixed variable rate design (MFVRD) for DPL electric and natural gas service in Delaware is under consideration by the DPSC.

• In New Jersey, a BSA proposed by ACE in 2009 was not approved and there is no BSA proposal currently pending.

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 under consideration by the DPSC in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption of electricity or natural gas) 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.

The following table shows, for each of the PHI utility subsidiaries, the current base rate cases filed. Please see the discussion below for more information concerning each of these filings.

Jurisdiction/Company	Current Requested Revenue Requirement Increase		Requested Return on Equity			Filing Date			Expected Timing of Decision
	(Millions of Dollars)
MD – Pepco Electric	$	60.8		10.25	%		11/30/12			Q3-2013
DE – DPL Gas		12.2		10.25	%		12/07/12			Q3-2013
NJ – ACE Electric		70.4		10.25	%		01/04/13	(a)		Q4-2013
DC – Pepco Electric		52.1		10.25	%		03/08/13			Q4-2013
DE – DPL Electric		42.0		10.25	%		03/22/13			Q4-2013
MD – DPL Electric		22.8		10.25	%		03/29/13			Q4-2013
Total	$	260.3

^(a) Filed 12/11/12; updated test period to 12 months actual data on 01/04/13.

Delaware

Gas Cost Rates

DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2012, DPL made its 2012 GCR filing. The rates proposed in the 2012 GCR would result in a GCR decrease of approximately 22.3%. On September 18, 2012, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2012, subject to refund and pending final DPSC approval. On April 24, 2013, DPL and the DPSC staff entered into a settlement agreement providing that the proposed GCR rates as filed by DPL should be approved. The settlement agreement is subject to DPSC approval. A DPSC decision on the settlement agreement is expected by the end of the third quarter of 2013.

Electric Distribution Base Rates

In December 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $31.8 million, based on a requested return on equity (ROE) of 10.75%, and requested approval of implementation of the MFVRD. In accordance with Delaware law and agreement with DPSC staff, DPL placed a total of $24.8 million of the requested rate increase into effect, subject to refund and pending final DPSC order. In November 2012, the DPSC approved a proposed settlement agreement entered into by DPL and the other parties to the proceeding that provided, among other things, for an annual rate increase of $22 million, based on an ROE of 9.75%. In February 2013, DPL refunded the billed amounts that exceeded the increase approved by the DPSC.

On March 22, 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $42 million, based on a requested ROE of 10.25%. The requested rate increase seeks to recover expenses associated with DPL’s ongoing efforts to maintain safe and reliable service. In accordance with Delaware law and because the DPSC suspended DPL’s full proposed increase, DPL plans to implement an interim increase of $2.5 million on June 1, 2013, subject to refund and pending final DPSC approval. A final DPSC decision is expected by the fourth quarter of 2013.

Gas Distribution Base Rates

On December 7, 2012, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. The filing seeks approval of an annual rate increase of approximately $12.2 million, based on a requested ROE of 10.25%. The requested rate increase is for the purposes of recovering expenses associated with DPL’s ongoing efforts to maintain safe and reliable service and to provide enhanced customer service technology. In January 2013, the DPSC suspended the full proposed increase and, as permitted by state law, DPL implemented an interim increase of $2.5 million on February 5, 2013, subject to refund and pending final DPSC approval. A final DPSC decision is expected by the third quarter of 2013.

District of Columbia

On March 8, 2013, Pepco filed an application with the District of Columbia Public Service Commission (DCPSC) to increase its electric distribution base rates by approximately $52.1 million annually, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering (i) Pepco’s expenses associated with ongoing efforts to maintain safe and reliable service for its customers, (ii) Pepco’s investment in infrastructure to maintain and harden the electric distribution system, and (iii) Pepco’s major reliability enhancement improvements. A final DCPSC decision is expected by the fourth quarter of 2013.

Maryland

DPL Electric Distribution Base Rates

On March 29, 2013, DPL submitted an application with the MPSC to increase its electric distribution base rates by approximately $22.8 million, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering reliability enhancements to serve Maryland customers. DPL also proposes a three-year Grid Resiliency Charge rider for recovery of costs totaling approximately $10.2 million associated with its plan to accelerate investments in electric distribution infrastructure in a condensed timeframe. Acceleration of resiliency improvements is one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below). The Grid Resiliency Charge, if approved, would become effective January 1, 2014 and be implemented as a rider that is separate from base rates and would include a reasonable return on investment. Specific projects under DPL’s plan include accelerating its tree-trimming cycle and upgrading five additional feeders per year for two years. In addition, DPL proposes a reliability performance-based mechanism that would allow DPL to earn up to $500,000 as an incentive for meeting enhanced reliability goals in 2015, but provides a credit to customers of up to $500,000 in total if DPL does not meet at least the minimum reliability performance targets. DPL requests that any credits or charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the fourth quarter of 2013.

Pepco Electric Distribution Base Rates

In December 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently reduced by Pepco to $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorizes Pepco to recover the actual cost of advanced metering infrastructure (AMI) meters installed during the test year and states that cost recovery for AMI deployment will only be allowed in future rate cases in which Pepco demonstrates that the system is proven to be cost effective. The new revenue rates and lower depreciation rates were effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of installed AMI meters; that motion remains pending.

On November 30, 2012, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $60.8 million, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering reliability enhancements to serve Maryland customers. Pepco also proposes a three-year Grid Resiliency Charge rider for recovery of costs totaling approximately $192 million associated with its plan to accelerate investments in infrastructure in a condensed timeframe. Acceleration of resiliency improvements is one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below). The Grid Resiliency Charge, if approved, would become effective January 1, 2014 and be implemented as a rider that is separate from base rates and would include a return on investment. Specific projects under Pepco’s plan include acceleration of its tree-trimming cycle, upgrade of 12 additional feeders per year for two years and undergrounding of six distribution feeders. In addition, Pepco proposes a reliability performance-based mechanism that would allow Pepco to earn up to $1 million as an incentive for meeting enhanced reliability goals in 2015, but provides a credit to customers of up to $1 million in total if Pepco does not meet at least the minimum reliability performance targets. Pepco requests that any credits/charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the third quarter of 2013.

New Jersey

Electric Distribution Base Rates

On December 11, 2012, ACE submitted an application with the NJBPU, updated on January 4, 2013, to increase its electric distribution base rates by approximately $70.4 million (excluding sales-and-use taxes), based on a requested ROE of 10.25%. This proposed net increase was comprised of (i) a proposed increase to ACE’s distribution rates of approximately $72.1 million and (ii) a net decrease to ACE’s Regulatory Asset Recovery Charge (costs associated with deferred, NJBPU-approved expenses incurred as part of ACE’s public service obligation) in the amount of approximately $1.7 million. The requested rate increase is primarily for the purposes of continuing to implement reliability-related investments and recovering system restoration costs associated with the June 2012 derecho storm and Hurricane Sandy. An NJBPU decision is expected by the fourth quarter of 2013.

In a March 20, 2013 order, the NJBPU established a generic proceeding to evaluate the prudency of major storm event restoration costs and expenses. Each New Jersey EDC was directed to file a separate proceeding for the evaluation of these costs. Those portions of ACE’s electric base rate filing pertaining to the recovery of major storm event expenditures will be evaluated in the context of the generic proceeding. On April 9, 2013, ACE filed a petition with the NJBPU to comply with the NJBPU’s generic storm cost order. All other issues in ACE’s base rate filing remain unchanged in the electric base rate proceeding discussed above.

Update and Reconciliation of Certain Under-Recovered Balances

In February 2012, ACE submitted a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program for low income customers) and ACE’s uncollected accounts and (iii) operating costs associated with ACE’s residential appliance cycling program. The filing proposed to recover the projected deferred under-recovered balance related to the NUGs of $113.8 million as of May 31, 2012 through a four-year amortization schedule. In June 2012, the NJBPU approved a stipulation of settlement signed by the parties, which provided for provisional rates that went into effect on July 1, 2012. The net impact of adjusting the charges (consisting of both the annual impact of the proposed four-year amortization of the historical under-recovered NUG balances of $127.0 million as of June 30, 2012 and the going-forward cost recovery of all the other charges for the period July 1, 2012 through May 31, 2013, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $55.3 million. The rates were deemed “provisional” because ACE’s filing was not updated for actual revenues and expenses for May and June 2012 until the March 5, 2013 petition described below was filed, after which a review by the NJBPU of the final underlying costs for reasonableness and prudence will be completed.

On March 5, 2013, ACE submitted a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges for the New Jersey Societal Benefit Program and ACE’s uncollected accounts and (iii) operating costs associated with ACE’s residential appliance cycling program. The net impact of adjusting the charges updated for actual data through March 31, 2013 (consisting of both the second year impact of the stipulated four-year amortization of the historical under-recovered NUG balances and the going-forward cost recovery of all the other charges for the period June 1, 2013 through May 31, 2014, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $52.2 million. ACE expects that the final order in this proceeding will finalize the rates for the proceeding filed in February 2012. ACE has requested the NJBPU to issue a decision by the end of the second quarter of 2013.

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland 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.

In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 MW beginning in 2015. The order requires Pepco, DPL and Baltimore Gas and Electric Company (BGE) (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process in amounts proportional to their relative Standard Offer Service (SOS) loads. Under the contract, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015. The order acknowledged the Contract EDCs’ concerns about the requirements of the contract and directed them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specified that the Contract EDCs will recover the associated costs through surcharges on their respective SOS customers.

In April 2012, a group of generating companies operating in the PJM region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, the Contract EDCs and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These circuit court appeals were consolidated in the Circuit Court for Baltimore City and stayed pending the issuance of a final order from the MPSC approving the form of contract.

On April 16, 2013, the MPSC issued an order approving a final form of the contract and directing the Contract EDCs to enter into the contract, in amounts proportional to their relative SOS loads, with the winning bidder within 20 days of the order (i.e, by May 6, 2013). The MPSC stated that the order, which approves timely and complete recovery by the Contract EDCs of the costs associated with the contract, constitutes a binding commitment that shall not be subject to future modification or rescission by the MPSC. Despite this commitment from the MPSC, Pepco and DPL believe that the attempt by the MPSC to bind a future commission in this manner may be subject to legal challenge, which challenge, if successful, could impair the right of Pepco and DPL to recover their costs in the future. In addition, the MPSC excluded from the contract a provision that Pepco and DPL believe is important to mitigate their financial risk because the provision, had it been included, would have required Pepco and DPL to make payments to the winning bidder under the contract only to the extent they were able to recover those costs (for example, Pepco and DPL believe the excluded provision would have protected them in the event a significant number of their SOS customers elect to buy their energy from alternative energy suppliers). In light of the issuance of the MPSC’s final order, the previously filed appeals of the MPSC’s actions in this case before the circuit court will now proceed. Pepco and DPL anticipate that, in accordance with the terms of the MPSC’s order, they will enter into the contract within the 20-day period; however, under its own terms, the contract will not become effective, if at all, until all legal proceedings related to this contract or the actions of the MPSC in the related proceeding have been resolved.

Until a final non-appealable court decision is rendered in connection with all such legal proceedings, PHI cannot predict (i) the extent of the negative effect that the contract for new generation may have on PHI’s, Pepco’s and DPL’s balance sheets, as well as their respective credit metrics, as calculated by independent rating agencies that evaluate and rate PHI, Pepco and DPL and each of their debt issuances, (ii) the effect on Pepco’s and DPL’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contract on the financial condition, results of operations and cash flows of each of PHI, Pepco and DPL.

Reliability Task Forces

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. Pepco’s electric distribution base rate case filed with the MPSC on November 30, 2012 and DPL’s electric distribution base rate case filed with the MPSC on March 29, 2013, each addresses the Grid Resiliency Task Force recommendations.

In August 2012, the District of Columbia mayor issued an Executive Order establishing the Mayor’s Power Line Undergrounding Task Force. The stated purpose of the Power Line Undergrounding Task Force is to pool the collective resources available in the District of Columbia to produce an analysis of the technical feasibility, infrastructure options and reliability implications of undergrounding new or existing overhead distribution facilities in the District of Columbia. These resources include legislative bodies, regulators, utility personnel, experts and other parties who could contribute in a meaningful way to the Power Line Undergrounding Task Force. The options that are available for financing these efforts are also to be evaluated to identify required legislative or regulatory actions to implement these recommendations. The results of this analysis are intended to help determine the path forward for these types of infrastructure improvements and additions. A written report from the Power Line Undergrounding Task Force setting forth the findings and recommendations was originally due on January 31, 2013 but the due date was extended to the second quarter of 2013.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company, as more fully described in Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – ACE Standard Offer Capacity Agreements” and Note (13), “Derivative Instruments and Hedging Activities.” ACE and the other New Jersey EDCs entered into the SOCAs under protest, arguing that the EDCs were denied due process and that the SOCAs violate certain of the requirements under the New Jersey law under which the SOCAs were established. The dispute is pending before the NJBPU and has been referred to an Administrative Law Judge for further consideration. On April 11, 2013, the Superior Court of New Jersey Appellate Division issued an order consolidating the EDCs’ state court appeal of the NJBPU order (filed by the EDCs with the Appellate Division of the New Jersey Superior Court in June 2011) with a similar challenge filed by several generators and instructing the Administrative Law Judge to complete proceedings by June 15, 2013. The matter remains pending.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the New Jersey law under which the SOCAs were established on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In September 2012, the District Court denied motions for summary judgment filed by ACE and the other plaintiffs, as well as cross-motions filed by defendants. The litigation remains pending and trial is scheduled to be completed on or before May 8, 2013. It has not been determined when the District Court will issue a decision.

MAPP Project

On August 24, 2012, the board of PJM terminated the Mid-Atlantic Power Pathway (MAPP) project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. As of December 31, 2012, PHI’s total costs related to the MAPP project were $102 million. In a 2008 Federal Energy Regulatory Commission (FERC) order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, PHI submitted a filing to FERC seeking recovery of $88 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

Various protests were submitted in response to PHI’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of Pepco and DPL, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by PHI to be $2 million), of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. PHI believes that the FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that PHI is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. PHI cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, PHI had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories, for use on other projects, and reclassified the remaining $88 million of capital expenditures to a regulatory asset. During the first quarter of 2013, PHI further transferred an additional $2 million of materials to inventories, for use on other projects, and expensed $2 million of abandoned costs as a result of FERC’s disallowance noted above, resulting in a regulatory asset of $84 million as of March 31, 2013. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. PHI intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with FERC against Pepco, DPL and ACE, as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s utilities provide. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. PHI, Pepco, DPL and ACE believe the allegations in this complaint are without merit and are vigorously contesting it. On April 3, 2013, Pepco, DPL and ACE filed their answer to this complaint, requesting that FERC dismiss the complaint against them on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

Potomac Electric Power Co [Member]

Regulatory Matters

(6) REGULATORY MATTERS

Rate Proceedings

Over the last several years, Pepco has proposed in each of its jurisdictions 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) was approved and implemented for electric service in Maryland and the District of Columbia. 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.

District of Columbia

On March 8, 2013, Pepco filed an application with the District of Columbia Public Service Commission (DCPSC) to increase its electric distribution base rates by approximately $52.1 million annually, based on a requested return on equity (ROE) of 10.25%. The requested rate increase is for the purpose of recovering (i) Pepco’s expenses associated with ongoing efforts to maintain safe and reliable service for its customers, (ii) Pepco’s investment in infrastructure to maintain and harden the electric distribution system, and (iii) Pepco’s major reliability enhancement improvements. A final DCPSC decision is expected by the fourth quarter of 2013.

Maryland

In December 2011, Pepco submitted an application with the Maryland Public Service Commission (MPSC) to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently reduced by Pepco to $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving, an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorizes Pepco to recover the actual cost of advanced metering infrastructure (AMI) meters installed during the test year and states that cost recovery for AMI deployment will only be allowed in future rate cases in which Pepco demonstrates that the system is proven to be cost effective. The new revenue rates and lower depreciation rates were effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of installed AMI meters; that motion remains pending.

On November 30, 2012, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $60.8 million, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering reliability enhancements to serve Maryland customers. Pepco also proposes a three-year Grid Resiliency Charge rider for recovery of costs totaling approximately $192 million associated with its plan to accelerate investments in infrastructure in a condensed timeframe. Acceleration of resiliency improvements is one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below). The Grid Resiliency Charge, if approved, would become effective January 1, 2014 and be implemented as a rider that is separate from base rates and would include a return on investment. Specific projects under Pepco’s plan include acceleration of its tree-trimming cycle, upgrade of 12 additional feeders per year for two years and undergrounding of six distribution feeders. In addition, Pepco proposes a reliability performance-based mechanism that would allow Pepco to earn up to $1 million as an incentive for meeting enhanced reliability goals in 2015, but provides a credit to customers of up to $1 million in total if Pepco does not meet at least the minimum reliability performance targets. Pepco requests that any credits/charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the third quarter of 2013.

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland 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.

In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 megawatts (MW) beginning in 2015. The order requires Pepco, Delmarva Power & Light Company (DPL) and Baltimore Gas and Electric Company (BGE) (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process in amounts proportional to their relative Standard Offer Service (SOS) loads. Under the contract, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015. The order acknowledged the Contract EDCs’ concerns about the requirements of the contract and directed them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specified that the Contract EDCs will recover the associated costs through surcharges on their respective SOS customers.

In April 2012, a group of generating companies operating in the PJM Interconnection, LLC (PJM) region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, the Contract EDCs and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These circuit court appeals were consolidated in the Circuit Court for Baltimore City and stayed pending the issuance of a final order from the MPSC approving the form of contract.

On April 16, 2013, the MPSC issued an order approving a final form of the contract and directing the Contract EDCs to enter into the contract, in amounts proportional to their relative SOS loads, with the winning bidder within 20 days of the order (i.e., by May 6, 2013). The MPSC stated that the order, which approves timely and complete recovery by the Contract EDCs of the costs associated with the contract, constitutes a binding commitment that shall not be subject to future modification or rescission by the MPSC. Despite this commitment from the MPSC, Pepco believes that the attempt by the MPSC to bind a future commission in this manner may be subject to legal challenge, which challenge, if successful, could impair its right to recover its costs in the future. In addition, the MPSC excluded from the contract a provision that Pepco believes is important to mitigate its financial risk because the provision, had it been included, would have required Pepco to make payments to the winning bidder under the contract only to the extent it was able to recover those costs (for example, Pepco believes the excluded provision would have protected it in the event a significant number of SOS customers elect to buy their energy from alternative energy suppliers). In light of the issuance of the MPSC’s final order, the previously filed appeals of the MPSC’s actions in this case before the circuit court will now proceed. Pepco anticipates that, in accordance with the terms of the MPSC’s order, it will enter into the contract within the 20-day period; however, under its own terms, the contract will not become effective, if at all, until all legal proceedings related to this contract or the actions of the MPSC in the related proceeding have been resolved.

Until a final non-appealable court decision is rendered in connection with all such legal proceedings, Pepco cannot predict (i) the extent of the negative effect that the contract for new generation may have on Pepco’s balance sheets, as well as its credit metrics, as calculated by independent rating agencies that evaluate and rate Pepco and each of its debt issuances, (ii) the effect on Pepco’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contract on the financial condition, results of operations and cash flows of Pepco.

Reliability Task Forces

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. Pepco’s electric distribution base rate case filed with the MPSC on November 30, 2012 addresses the Grid Resiliency Task Force recommendations.

In August 2012, the District of Columbia mayor issued an Executive Order establishing the Mayor’s Power Line Undergrounding Task Force. The stated purpose of the Power Line Undergrounding Task Force is to pool the collective resources available in the District of Columbia to produce an analysis of the technical feasibility, infrastructure options and reliability implications of undergrounding new or existing overhead distribution facilities in the District of Columbia. These resources include legislative bodies, regulators, utility personnel, experts and other parties who could contribute in a meaningful way to the Power Line Undergrounding Task Force. The options that are available for financing these efforts are also to be evaluated to identify required legislative or regulatory actions to implement these recommendations. The results of this analysis are intended to help determine the path forward for these types of infrastructure improvements and additions. A written report from the Power Line Undergrounding Task Force setting forth the findings and recommendations was originally due on January 31, 2013 but the due date was extended to the second quarter of 2013.

MAPP Project

On August 24, 2012, the board of PJM terminated the Mid-Atlantic Power Pathway (MAPP) project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. As of December 31, 2012, Pepco’s total costs related to the MAPP project were $64 million. In a 2008 Federal Energy Regulatory Commission (FERC) order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, Pepco submitted a filing to FERC seeking recovery of $50 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

Various protests were submitted in response to Pepco’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of Pepco, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by Pepco to be $1 million) of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. Pepco believes that the FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request on behalf of Pepco of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that Pepco is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. Pepco cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, Pepco had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories, for use on other projects, and reclassified the remaining $50 million of capital expenditures to a regulatory asset. During the first quarter of 2013, Pepco further transferred an additional $2 million of materials to inventories, for use on other projects, and expensed $1 million of abandoned costs as a result of FERC’s disallowance noted above, resulting in a regulatory asset of $47 million as of March 31, 2013. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. Pepco intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey filed a joint complaint with FERC against Pepco, DPL and Atlantic City Electric Company (ACE), as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that Pepco provides. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for Pepco is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. Pepco believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, Pepco filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

Delmarva Power & Light Co/De [Member]

Regulatory Matters

(7) REGULATORY MATTERS

Rate Proceedings

Over the last several years, DPL has proposed in each its jurisdictions 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) was approved and implemented for electric service in Maryland.

• A modified fixed variable rate design (MFVRD) is under consideration by the DPSC.

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

Delaware

Gas Cost Rates

DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2012, DPL made its 2012 GCR filing. The rates proposed in the 2012 GCR would result in a GCR decrease of approximately 22.3%. On September 18, 2012, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2012, subject to refund and pending final DPSC approval. On April 24, 2013, DPL and the DPSC staff entered into a settlement agreement providing that the proposed GCR rates as filed by DPL should be approved. The settlement agreement is subject to DPSC approval. A DPSC decision on the settlement agreement is expected by the end of the third quarter of 2013.

Electric Distribution Base Rates

In December 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $31.8 million, based on a requested return on equity (ROE) of 10.75%, and requested approval of implementation of the MFVRD. In accordance with Delaware law and agreement with DPSC staff, DPL placed a total of $24.8 million of the requested rate increase into effect, subject to refund and pending final DPSC order. In November 2012, the DPSC approved a proposed settlement agreement entered into by DPL and the other parties to the proceeding that provided, among other things, for an annual rate increase of $22 million, based on an ROE of 9.75%. In February 2013, DPL refunded the billed amounts that exceeded the increase approved by the DPSC.

On March 22, 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $42 million, based on a requested ROE of 10.25%. The requested rate increase seeks to recover expenses associated with DPL’s ongoing efforts to maintain safe and reliable service. In accordance with Delaware law and because the DPSC suspended, DPL’s full proposed increase, DPL plans to implement an interim increase of $2.5 million on June 1, 2013, subject to refund and pending final DPSC approval. A final DPSC decision is expected by the fourth quarter of 2013.

Gas Distribution Base Rates

On December 7, 2012, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. The filing seeks approval of an annual rate increase of approximately $12.2 million, based on a requested ROE of 10.25%. The requested rate increase is for the purposes of recovering expenses associated with DPL’s ongoing efforts to maintain safe and reliable service and to provide enhanced customer service technology. In January 2013, the DPSC suspended the full proposed increase and, as permitted by state law, DPL implemented an interim increase of $2.5 million on February 5, 2013, subject to refund and pending final DPSC approval. A final DPSC decision is expected by the third quarter of 2013.

Maryland

Electric Distribution Base Rates

On March 29, 2013, DPL submitted an application with the Maryland Public Service Commission (MPSC) to increase its electric distribution base rates by approximately $22.8 million, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering reliability enhancements to serve Maryland customers. DPL also proposes a three-year Grid Resiliency Charge rider for recovery of costs totaling approximately $10.2 million associated with its plan to accelerate investments in electric distribution infrastructure in a condensed timeframe. Acceleration of resiliency improvements is one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below). The Grid Resiliency Charge, if approved, would become effective January 1, 2014 and be implemented as a rider that is separate from base rates and would include a reasonable return on investment. Specific projects under DPL’s plan include accelerating its tree-trimming cycle and upgrading five additional feeders per year for two years. In addition, DPL proposes a reliability performance-based mechanism that would allow DPL to earn up to $500,000 as an incentive for meeting enhanced reliability goals in 2015, but provides a credit to customers of up to $500,000 in total if DPL does not meet at least the minimum reliability performance targets. DPL requests that any credits or charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the fourth quarter of 2013.

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland 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.

In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 MW beginning in 2015. The order requires DPL, Potomac Electric Power Company (Pepco) and Baltimore Gas and Electric Company (BGE) (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process in amounts proportional to their relative Standard Offer Service (SOS) loads. Under the contract, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015. The order acknowledged the Contract EDCs’ concerns about the requirements of the contract and directed them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specified that the Contract EDCs will recover the associated costs through surcharges on their respective SOS customers.

In April 2012, a group of generating companies operating in the PJM Interconnection, LLC (PJM) region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, the Contract EDCs and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These appeals were consolidated in the Circuit Court for Baltimore City and stayed pending the issuance of a final order from the MPSC approving the form of contract.

On April 16, 2013, the MPSC issued an order approving a final form of the contract and directing the Contract EDCs to enter into the contract, in amounts proportional to their relative SOS loads, with the winning bidder within 20 days of the order (i.e., by May 6, 2013). The MPSC stated that the order, which approves timely and complete recovery by the Contract EDCs of the costs associated with the contract, constitutes a binding commitment that shall not be subject to future modification or rescission by the MPSC. Despite this commitment from the MPSC, DPL believes that the attempt by the MPSC to bind a future commission in this manner may be subject to legal challenge, which challenge, if successful, could impair its right to recover its costs in the future. In addition, the MPSC excluded from the contract a provision that DPL believes is important to mitigate its financial risk because the provision, had it been included, would have required DPL to make payments to the winning bidder under the contract only to the extent it was able to recover those costs (for example, DPL believes the excluded provision would have protected it in the event a significant number of its SOS customers elect to buy their energy from alternative energy suppliers). In light of the issuance of the MPSC’s final order, the previously filed appeals of the MPSC’s actions in this case before the circuit court will now proceed. DPL anticipates that, in accordance with the terms of the MPSC’s order, it will enter into the contract within the 20-day period; however, under its own terms, the contract will not become effective, if at all, until all legal proceedings related to this contract or the actions of the MPSC in the related proceeding have been resolved.

Until a final non-appealable court decision is rendered in connection with all such legal proceedings, DPL cannot predict (i) the extent of the negative effect that the contract for new generation may have on DPL’s balance sheets, as well as its credit metrics, as calculated by independent rating agencies that evaluate and rate DPL and its debt issuances, (ii) the effect on DPL’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contract on the financial condition, results of operations and cash flows of DPL.

Reliability Task Force

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. DPL’s electric distribution base rate case filed with the MPSC on March 29, 2013 addresses the Grid Resiliency Task Force recommendations.

MAPP Project

On August 24, 2012, the board of PJM terminated the Mid-Atlantic Power Pathway (MAPP) project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. As of December 31, 2012, DPL’s total costs related to the MAPP project were $38 million. In a 2008 Federal Energy Regulatory Commission (FERC) order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, DPL submitted a filing to FERC seeking recovery of $38 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

Various protests were submitted in response to DPL’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of DPL, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by DPL to be $1 million) of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. DPL believes that the FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request on behalf of DPL of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that DPL is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. DPL cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, DPL had reclassified all $38 million of capital expenditures with respect to the MAPP project to a regulatory asset. During the first quarter of 2013, DPL expensed $1 million of prudently incurred abandoned costs as a result of FERC’s disallowance noted above, resulting in a regulatory asset of $37 million as of March 31, 2013. The regulatory asset includes the costs of land, land rights, engineering and design, environmental services, and project management and administration. DPL intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land and land rights.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with FERC against DPL, Pepco and Atlantic City Electric Company (ACE), as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that DPL provides. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for DPL is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. DPL believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, DPL filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

Atlantic City Electric Co [Member]

Regulatory Matters

(6) REGULATORY MATTERS

Rate Proceedings

Electric Distribution Base Rates

On December 11, 2012, ACE submitted an application with the NJBPU, updated on January 4, 2013, to increase its electric distribution base rates by approximately $70.4 million (excluding sales-and-use taxes), based on a requested ROE of 10.25%. This proposed net increase was comprised of (i) a proposed increase to ACE’s distribution rates of approximately $72.1 million and (ii) a net decrease to ACE’s Regulatory Asset Recovery Charge (costs associated with deferred, NJBPU-approved expenses incurred as part of ACE’s public service obligation) in the amount of approximately $1.7 million. The requested rate increase is primarily for the purposes of continuing to implement reliability-related investments and recovering system restoration costs associated with the June 2012 derecho storm and Hurricane Sandy. An NJBPU decision is expected by the fourth quarter of 2013.

In a March 20, 2013 order, the NJBPU established a generic proceeding to evaluate the prudency of major storm event restoration costs and expenses. Each New Jersey EDC was directed to file a separate proceeding for the evaluation of these costs. Those portions of ACE’s electric base rate filing pertaining to the recovery of major storm event expenditures will be evaluated in the context of the generic proceeding. On April 9, 2013, ACE filed a petition with the NJBPU to comply with the NJBPU’s generic storm cost order. All other issues in ACE’s base rate filing remain unchanged in the electric base rate proceeding discussed above.

Update and Reconciliation of Certain Under-Recovered Balances

In February 2012, ACE submitted a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges for the New Jersey Societal Benefit Program and ACE’s uncollected accounts, and (iii) operating costs associated with ACE’s residential appliance cycling program. The filing proposed to recover the projected deferred under-recovered balance related to the NUGs of $113.8 million as of May 31, 2012 through a four-year amortization schedule. In June 2012, the NJBPU approved a stipulation of settlement signed by the parties, which provided for provisional rates that went into effect on July 1, 2012. The net impact of adjusting the charges (consisting of both the annual impact of the proposed four-year amortization of the historical under-recovered NUG balances of $127.0 million as of June 30, 2012 and the going-forward cost recovery of all the other charges for the period July 1, 2012 through May 31, 2013, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $55.3 million. The rates were deemed “provisional” because ACE’s filing was not updated for actual revenues and expenses for May and June 2012 until the March 5, 2013 petition described below was filed, after which a review by the NJBPU of the final underlying costs for reasonableness and prudence will be completed.

On March 5, 2013, ACE submitted a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program for low income customers) and ACE’s uncollected accounts, and (iii) operating costs associated with ACE’s residential appliance cycling program. The net impact of adjusting the charges updated for actual data through March 31, 2013 (consisting of both the second year impact of the stipulated four-year amortization of the historical under-recovered NUG balances and the going-forward cost recovery of all the other charges for the period June 1, 2013 through May 31, 2014, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $52.2 million. ACE expects that the final order in this proceeding will finalize the rates for the proceeding filed in February 2012. ACE has requested the NJBPU to issue a decision by the end of the second quarter of 2013.

Standard Offer Capacity Agreements

In April 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company, as more fully described in Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – ACE Standard Offer Capacity Agreements” and Note (10), “Derivative Instruments and Hedging Activities.” ACE and the other New Jersey EDCs entered into the SOCAs under protest, arguing that the EDCs were denied due process and that the SOCAs violate certain of the requirements under the New Jersey law under which the SOCAs were established. The dispute is pending before the NJBPU and has been referred to an Administrative Law Judge for further consideration. On April 11, 2013, the Superior Court of New Jersey Appellate Division issued an order consolidating the EDCs’ state court appeal of the NJBPU order (filed by the EDCs with the Appellate Division of the New Jersey Superior Court in June 2011) with a similar challenge filed by several generators and instructing the Administrative Law Judge to complete proceedings by June 15, 2013. The matter remains pending.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the the New Jersey law under which the SOCAs were established on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In September 2012, the District Court denied motions for summary judgment filed by ACE and the other plaintiffs, as well as cross-motions filed by defendants. The litigation remains pending and trial is scheduled to be completed on or before May 8, 2013. It has not been determined when the District Court will issue a decision.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Electric Municipal Corporation, Inc., filed a joint complaint with the Federal Energy Regulatory Commission (FERC) against ACE, Potomac Electric Power Company (Pepco) and Delmarva Power & Light Company (DPL), as well as Baltimore Gas and Electric Company. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that ACE provides. The complainants claim to support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for ACE is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. As currently authorized, the 10.8% base ROE for facilities placed into service prior to 2006 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. ACE believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, ACE filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

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Derivative Instruments And Hedging Activities (Activity Of Energy Commodity Contracts Designated As Cash Flow Hedges) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Amount of net pre-tax loss arising during the period included in Accumulated Other Comprehensive Loss	$ 0		$ 0
Fuel and Purchased Energy expense	3		7
Revenue		[1]		[1]
Total net pre-tax loss reclassified into income	3		7
Net pre-tax gain on commodity derivatives included in Accumulated Other Comprehensive Loss	3		7
Amount reclassified from AOCL to income	$ 0		$ 0

[1] For the three months ended March 31, 2013 and 2012, no amounts were reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur.

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Segment Information

3 Months Ended

Mar. 31, 2013

Segment Information

(5) SEGMENT INFORMATION

Pepco Holdings’ management has identified its operating segments at March 31, 2013 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 months ended March 31, 2013 and 2012 is as follows:

	Three Months Ended March 31, 2013
	(millions of dollars)
	Power Delivery		Pepco Energy Services		Other Non- Regulated			Corporate and Other  (a)			PHI Consolidated
Operating Revenue	$	1,124	$	97	$	(368	)(b)	$	(1	)	$	852
Operating Expenses (c)		1,001		94		—			(7	)		1,088
Operating Income (Loss)		123		3		(368	)		6			(236	)
Interest Income		—		—		1			(1	)		—
Interest Expense		56		—		1			10			67
Other Income		6		1		1			—			8
Preferred Stock Dividends		—		—		1			(1	)		—
Income Tax Expense (d)		15		1		53	(e)		66			135
Net Income (Loss) from Continuing Operations		58		3		(421	)		(70	)		(430	)
Total Assets (excluding Assets Held For Sale)		12,453		368		882			1,952			15,655
Construction Expenditures	$	282	$	1	$	—		$	13		$	296

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. 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. Corporate and Other includes intercompany amounts of $(1) million for Operating Revenue, $(1) million for Operating Expenses, $(3) million for Interest Income, $(4) million for Interest Expense and $(1) million for Preferred Stock Dividends.

(b) Includes a non-cash pre-tax charge of $373 million to reduce the carrying value of the cross-border energy lease investments.

(c) Includes depreciation and amortization expense of $112 million, consisting of $104 million for Power Delivery, $2 million for Pepco Energy Services and $6 million for Corporate and Other.

(d) Includes after-tax interest associated with uncertain and effectively settled tax positions allocated to each member of the consolidated group, including a $12 million interest benefit for Power Delivery and interest expense of $16 million and $66 million for Other Non-Regulated and Corporate and Other, respectively.

(e) Includes non-cash charges of $64 million primarily for the tax consequences associated with PHI’s change in intent regarding foreign investment opportunities associated with the cross-border energy lease investments and $101 million representing the establishment of valuation allowances against certain deferred tax assets of PCI included in Other Non-Regulated.

	Three Months Ended March 31, 2012
	(millions of dollars)
	Power Delivery			Pepco Energy Services		Other Non- Regulated		Corporate and Other  (a)			PHI Consolidated
Operating Revenue	$	1,055		$	178	$	13	$	(4	)	$	1,242
Operating Expenses (b)		954			169		1		(13	)		1,111
Operating Income		101			9		12		9			131
Interest Income		—			—		1		(1	)		—
Interest Expense		53			1		3		8			65
Other Income (Expenses)		8			—		1		(1	)		8
Preferred Stock Dividends		—			—		1		(1	)		—
Income Tax Expense (Benefit)		9	(c)		3		—		(1	)		11
Net Income from Continuing Operations		47			5		10		1			63
Total Assets (excluding Assets Held For Sale)		11,473			583		1,487		1,684			15,227
Construction Expenditures	$	280		$	5	$	—	$	6		$	291

(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. 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. Corporate and Other includes intercompany amounts of $(4) million for Operating Revenue, $(6) million for Operating Expenses, $(5) million for Interest Income, $(5) million for Interest Expense and $(1) million for Preferred Stock Dividends.

(b) Includes depreciation and amortization expense of $110 million, consisting of $99 million for Power Delivery, $6 million for Pepco Energy Services, $1 million for Other Non-Regulated and $4 million for Corporate and Other.

(c) Includes income tax benefits of $10 million related to uncertain and effectively settled tax positions, primarily due to the effective settlement with the Internal Revenue Service with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position at Pepco.

Potomac Electric Power Co [Member]

Segment Information

(5) SEGMENT INFORMATION

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

Delmarva Power & Light Co/De [Member]

Segment Information

(5) SEGMENT INFORMATION

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

Atlantic City Electric Co [Member]

Segment Information

(5) SEGMENT INFORMATION

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

XML

Goodwill

3 Months Ended

Mar. 31, 2013

Goodwill

(6) GOODWILL

PHI’s goodwill balance of $1.4 billion was unchanged during the three months ended March 31, 2013. Substantially all of PHI’s goodwill balance 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, 2012 indicated that goodwill was not impaired. For the three months ended March 31, 2013, 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, 2013.

Delmarva Power & Light Co/De [Member]

Goodwill

(6) GOODWILL

DPL’s goodwill balance of $8 million was unchanged during the three months ended March 31, 2013. 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, 2012 indicated that goodwill was not impaired. For the three months ended March 31, 2013, 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, 2013.

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Leasing Activities

3 Months Ended

Mar. 31, 2013

Leases [Abstract]

Leasing Activities

(8) LEASING ACTIVITIES

Investment in Finance Leases Held in Trust

Between 1994 and 2002, PCI entered into eight 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 of these lease investments is structured as a sale and leaseback transaction commonly referred to as a sale-in, lease-out, or SILO, transaction. Each lease investment is comprised of a number of leases. During the second quarter of 2011 and the third quarter of 2012, PHI entered into early termination agreements with several lessees comprising two of the eight lease investments and a small portion of the leases comprising a third lease investment. As of March 31, 2013 and December 31, 2012, the lease portfolio consisted of six investments with a net investment value of $869 million and $1,237 million, respectively.

The components of the cross-border energy lease investments as of March 31, 2013 and December 31, 2012 are summarized below:

	March 31, 2013			December 31, 2012
	(millions of dollars)
Scheduled lease payments to PHI, net of non-recourse debt	$	1,842		$	1,852
Less: Unearned and deferred income		(973	)		(615	)
Investment in finance leases held in trust		869			1,237
Less: Deferred income tax liabilities		(95	)		(756	)
Net investment in finance leases held in trust	$	774		$	481

Income recognized from cross-border energy lease investments was comprised of the following for the three months ended March 31, 2013 and 2012:

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
Pre-tax income from PHI’s cross-border energy lease investments (included in Other Revenue)	$	5		$	13
Non-cash charge to reduce carrying value of PHI’s cross-border energy lease investments		(373	)		—
Pre-tax (loss) income from PHI’s cross-border energy lease investments after adjustment		(368	)		13
Income tax (benefit) expense related to PHI’s cross-border energy lease investments, including interest expense on uncertain tax positions of $16 million		(48	)		1
Net (loss) income from PHI’s cross-border energy lease investments	$	(320	)	$	12

PHI is required to assess on a periodic basis the likely outcome of tax positions relating to its cross-border energy lease investments and, if there is a change or a projected change in the timing of the estimated tax benefits generated by the transactions, PHI is required to recalculate the value of its net investment.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI has determined that its tax position with respect to the benefits associated with its cross-border energy leases no longer meets the more likely than not standard of recognition for accounting purposes, and PHI recorded an after-tax non-cash charge of $377 million in the first quarter of 2013, consisting of the following components:

• A non-cash pre-tax charge of $373 million ($307 million after-tax) to reduce the carrying value of these cross-border energy lease investments under FASB guidance on leases (ASC 840). This pre-tax charge has been recorded in the consolidated statement of income as a reduction in Other Operating revenue.

• A non-cash charge of $70 million after-tax to reflect the anticipated additional net interest expense under FASB guidance for income taxes (ASC 740), related to estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed. This after-tax charge has been recorded in the consolidated statement of income as an increase in income tax expense and was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in the recognition of a $12 million interest benefit for the Power Delivery segment and interest expense of $16 million and $66 million for the Other Non-Regulated and Corporate and Other segments, respectively.

PHI had also previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. In view of the change in PHI's tax position with respect to the tax benefits associated with the cross-border energy lease investments and PHI's resulting decision to pursue the early termination of these investments, management has concluded that these business assumptions are no longer supportable and the tax effects of this conclusion are reflected in the after-tax charge of $307 million described above.

PHI has accrued no penalties associated with its re-assessment of the likely outcome of tax positions associated with the cross-border energy lease investments. While the Internal Revenue Service (IRS) could require PHI to pay a penalty of up to 20% of the amount of additional taxes due, PHI believes that it is more likely than not that no such penalty will be incurred, and therefore no amount for any potential penalty was included in the charge.

In March 2013, PHI began to pursue the early termination of its remaining cross-border energy lease investments with its lessees. During April 2013, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the six lease investments and one of the leases included in a second lease investment. Upon closing, PHI received aggregate net cash proceeds of $168 million (net of aggregate termination payments of $804 million used to retire the non-recourse debt associated with the terminated leases) and expects to record a net pre-tax loss of approximately $27 million in the second quarter of 2013, representing the excess of the carrying value of the terminated leases over the net cash proceeds received. PHI estimates that the early termination of the remaining cross-border energy lease investments could be accomplished during 2013. The aggregate financial impact of the early termination of the remaining cross-border energy lease investments is not determinable at this time, but management believes that any gains or losses incurred in the aggregate will not be material; however, there may be individual lease terminations that result in offsetting material gains and losses.

For additional information concerning these cross-border energy lease investments, see Note (15), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments.”

To ensure credit quality, PHI regularly monitors the financial performance and condition of the lessees under its cross-border energy lease investments. Changes in credit quality are also assessed to determine if they should be reflected in the carrying value of the leases. PHI compares each lessee’s performance to 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 their company and asset performance. If the annual compliance requirements or minimum credit ratings are not met, remedies are available under the leases. At March 31, 2013, all lessees were in compliance with the terms and conditions of their lease agreements.

The table below shows PHI’s net investment in these leases by the published credit ratings of the lessees as of March 31, 2013 and December 31, 2012:

Lessee Rating (a)	March 31, 2013		December 31, 2012
	(millions of dollars)
Rated Entities
AA/Aa and above	$	537	$	766
A		332		471
Total	$	869	$	1,237

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

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Derivative Instruments And Hedging Activities (Net Outstanding Commodity Forward Contracts Quantities And Net Position That Did Not Qualify For Hedge Accounting) (Detail)	3 Months Ended	12 Months Ended
	Mar. 31, 2013 ForwardContracts	Dec. 31, 2012 ForwardContracts
Pepco Energy Services [Member] | Financial Transmission Rights (MWh) [Member]
Derivative [Line Items]
Commodity forward contracts	86,746	181,008
Net Position	Long	Long
Pepco Energy Services [Member] | Electricity (MWh) [Member]
Derivative [Line Items]
Commodity forward contracts	131,640	261,240
Net Position	Long	Long
Delmarva Power & Light Co/De [Member] | Natural Gas (MMBtu)) [Member]
Derivative [Line Items]
Commodity forward contracts	3,245,000	3,838,000
Net Position	Long	Long

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Discontinued Operations (Net Outstanding Commodity Forward Contracts That Did Not Qualify For Hedge Accounting) (Detail) (Discontinued Operations [Member], Natural Gas (MMBtu)) [Member])	3 Months Ended	12 Months Ended
	Mar. 31, 2013 MMBTU	Dec. 31, 2012 MMBTU
Discontinued Operations [Member] | Natural Gas (MMBtu)) [Member]
Derivative [Line Items]
Commodity forward contracts	2,047,500	2,867,500
Net Position	Long	Long

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Derivative Instruments And Hedging Activities (Net Outstanding Commodity Forward Contracts That Did Not Qualify For Hedge Accounting) (Detail)	3 Months Ended	12 Months Ended
	Mar. 31, 2013 ForwardContracts	Dec. 31, 2012 ForwardContracts
Delmarva Power & Light Co/De [Member] | Natural Gas (MMBtu)) [Member]
Derivative [Line Items]
Commodity forward contracts	3,245,000	3,838,000
Net Position	Long	Long
Atlantic City Electric Co [Member] | Capacity (MWs) [Member]
Derivative [Line Items]
Commodity forward contracts	180	180
Net Position	Long	Long

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Derivative Instruments And Hedging Activities (Schedule Of Derivative Gain (Loss) Amounts Recognized In Income) (Detail) (Pepco Energy Services [Member], USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Pepco Energy Services [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Reclassification of mark-to-market to realized on settlement of contracts	$ 2	$ 2
Unrealized mark-to-market loss		(4)
Total net gain (loss)	$ 2	$ (2)

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Derivative Instruments And Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2013

Fair Value Of Derivative Instruments By Balance Sheet Location

	As of March 31, 2013
Balance Sheet Caption	Derivatives Designated as Hedging Instruments (a)			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative assets (current assets)	$	—		$	1		$	1		$	(1	)	$	—
Derivative assets (non-current assets)		—			8			8			—			8
Total Derivative assets		—			9			9			(1	)		8
Derivative liabilities (current liabilities)		(2	)		(2	)		(4	)		2			(2	)
Derivative liabilities (non-current liabilities)		—			(11	)		(11	)		—			(11	)
Total Derivative liabilities		(2	)		(13	)		(15	)		2			(13	)
Net Derivative (liability) asset	$	(2	)	$	(4	)	$	(6	)	$	1		$	(5	)

(a) Amounts included in Derivatives Designated as Hedging Instruments primarily consist of derivatives that were designated as cash flow hedges prior to Pepco Energy Services’ election to discontinue cash flow hedge accounting for these derivatives.

	As of December 31, 2012
Balance Sheet Caption	Derivatives Designated as Hedging Instruments (a)			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative assets (current assets)	$	—		$	1		$	1		$	—	$	1
Derivative assets (non-current assets)		—			8			8			—		8
Total Derivative assets		—			9			9			—		9
Derivative liabilities (current liabilities)		(5	)		(8	)		(13	)		6		(7	)
Derivative liabilities (non-current liabilities)		—			(11	)		(11	)		—		(11	)
Total Derivative liabilities		(5	)		(19	)		(24	)		6		(18	)
Net Derivative (liability) asset	$	(5	)	$	(10	)	$	(15	)	$	6	$	(9	)

(a) Amounts included in Derivatives Designated as Hedging Instruments primarily consist of derivatives that were designated as cash flow hedges prior to Pepco Energy Services’ election to discontinue cash flow hedge accounting for these derivatives.

Schedule Of Cash Collateral Offset Against Derivative Positions

	March 31, 2013			December 31, 2012
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	2		$	6
Cash collateral received from counterparties with the obligation to return		(1	)		—

(a) Includes cash deposits on commodity brokerage accounts.

Activity Of Energy Commodity Contracts Designated As Cash Flow Hedges

	Three Months Ended March 31,
	2013		2012
	(millions of dollars)
Amount of net pre-tax loss arising during the period included in Accumulated Other Comprehensive Loss	$	—	$	—
Amount of net pre-tax loss reclassified into income:
Effective portion:
Fuel and Purchased Energy expense		3		7
Ineffective portion: (a)
Revenue		—		—
Total net pre-tax loss reclassified into income		3		7
Net pre-tax gain on commodity derivatives included in Accumulated Other Comprehensive Loss	$	3	$	7

(a) For the three months ended March 31, 2013 and 2012, no amounts were reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur.

Cash Flow Hedges Included In Accumulated Other Comprehensive Loss

Contracts	As of March 31, 2013				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Energy commodity (a)	$	1	$	1		2 months
Interest rate		10		1		233 months
Total	$	11	$	2

(a) The unrealized derivative losses recorded in AOCL relate to forecasted physical electricity purchases which are used to supply retail electricity contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on PHI’s consolidated balance sheet for the retail contracts and the purchase cost is not recognized until the period of distribution.

Contracts	As of March 31, 2012				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Energy commodity (a)	$	11	$	10		14 months
Interest rate		10		1		245 months
Total	$	21	$	11

(a) The unrealized derivative losses recorded in AOCL relate to forecasted physical and electricity purchases which are used to supply retail electricity contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on PHI’s consolidated balance sheet for the retail contracts and the purchase cost is not recognized until the period of distribution.

Schedule Of Derivative Gain (Loss) Amounts Recognized In Income

	Three Months Ended March  31,
	2013		2012
	(millions of dollars)
Reclassification of mark-to-market to realized on settlement of contracts	$	2	$	2
Unrealized mark-to-market loss		—		(4	)
Total net gain (loss)	$	2	$	(2	)

Net Unrealized Derivative Gain (Loss) Deferred As Regulatory Asset Or Liability

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
Net unrealized gain (loss) arising during the period	$	2		$	(4	)
Net realized loss recognized during the period		(4	)		(7	)

Net Outstanding Commodity Forward Contracts That Did Not Qualify For Hedge Accounting

	March 31, 2013				December 31, 2012
Commodity	Quantity		Net Position		Quantity		Net Position
DPL – Natural gas (one Million British Thermal Units (MMBtu))		3,245,000		Long		3,838,000		Long
ACE – Capacity (MWs)		180		Long		180		Long

Discontinued Operations [Member]

Fair Value Of Derivative Instruments By Balance Sheet Location

	As of March 31, 2013
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)	$	—		$	(7	)	$	(7	)	$	7	$	—
Derivative liabilities (non-current liabilities)		—			(1	)		(1	)		1		—
Net Derivative liability	$	—		$	(8	)	$	(8	)	$	8	$	—
	As of December 31, 2012
Balance Sheet Caption	Derivatives Designated as Hedging Instruments (a)			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative liabilities (current liabilities)	$	(5	)	$	(5	)	$	(10	)	$	10	$	—
Derivative liabilities (non-current liabilities)		(1	)		(1	)		(2	)		2		—
Net Derivative (liability) asset	$	(6	)	$	(6	)	$	(12	)	$	12	$	—

(a) Amounts included in Derivatives Designated as Hedging Instruments primarily consist of derivatives that were designated as cash flow hedges prior to Pepco Energy Services’ election to discontinue cash flow hedge accounting for these derivatives.

Schedule Of Cash Collateral Offset Against Derivative Positions

	March 31, 2013		December 31, 2012
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	8	$	12

(a) Includes cash deposits on commodity brokerage accounts.

Activity Of Energy Commodity Contracts Designated As Cash Flow Hedges

	Three Months Ended March 31,
	2013		2012
	(millions of dollars)
Amount of net pre-tax loss arising during the period included in Accumulated Other Comprehensive Loss	$	—	$	—
Amount of net pre-tax loss reclassified into income:
Effective portion:
Income from Discontinued Operations, Net of Income Taxes		1		6
Ineffective portion: (a)
Income from Discontinued Operations, Net of Income Taxes		4		—
Total net pre-tax loss reclassified into Income from Discontinued Operations, Net of Income Taxes		5		6
Net pre-tax gain on commodity derivatives included in Accumulated Other Comprehensive Loss	$	5	$	6

(a) Included in the table above is a loss of $4 million for the three months ended March 31, 2013, which was reclassified from AOCL to Income from Discontinued Operations, Net of Income Taxes because the forecasted hedged transactions were deemed probable not to occur. For the three months ended March 31, 2012, no amounts were reclassified from AOCL to Income from Discontinued Operations, Net of Income Taxes because the forecasted hedged transactions were deemed probable not to occur.

Cash Flow Hedges Included In Accumulated Other Comprehensive Loss

Contracts	As of March 31, 2012				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Energy commodity (a)	$	10	$	7		26 months
Total	$	10	$	7

(a) The unrealized derivative losses recorded in AOCL relate to forecasted physical natural gas purchases which are used to supply retail natural gas contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on the retail natural gas supply business of Pepco Energy Services’ balance sheet and the purchase cost is not recognized until the period of distribution.

Schedule Of Derivative Gain (Loss) Amounts Recognized In Income

	Three Months Ended March 31,
	2013			2012
	(millions of dollars)
Reclassification of mark-to-market to realized on settlement of contracts	$	2		$	8
Unrealized mark-to-market loss		(3	)		(6	)
Total net (loss) gain	$	(1	)	$	2

Net Outstanding Commodity Forward Contracts That Did Not Qualify For Hedge Accounting

	March 31, 2013				December 31, 2012
Commodity	Quantity		Net Position		Quantity		Net Position
Natural gas (MMBtu)		2,047,500		Long		2,867,500		Long

Pepco Energy Services [Member]

Outstanding Energy Commodity Contracts Employed As Cash Flow Hedges

	March 31, 2013				December 31, 2012
Commodity	Quantity		Net Position		Quantity		Net Position
Financial transmission rights (MWh)		86,746		Long		181,008		Long
Electricity (MWh)		131,640		Long		261,240		Long

Delmarva Power & Light Co/De [Member]

Fair Value Of Derivative Instruments By Balance Sheet Location

	As of March 31, 2013
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)	$	—	$	1	$	1	$	(1	)	$	—
Derivative assets (non-current assets)		—		—		—		—			—
Net Derivative asset	$	—	$	1	$	1	$	(1	)	$	—

	As of December 31, 2012
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)	$	—	$	(4	)	$	(4	)	$	—	$	(4	)
Derivative liabilities (non-current liabilities)		—		—			—			—		—
Net Derivative liability	$	—	$	(4	)	$	(4	)	$	—	$	(4	)

Schedule Of Cash Collateral Offset Against Derivative Positions

	March 31, 2013			December 31, 2012
	(millions of dollars)
Cash collateral received from counterparties with the obligation to return	$	(1	)	$	—

Net Unrealized Derivative Gain (Loss) Deferred As Regulatory Asset Or Liability

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
Net unrealized gains (losses) arising during the period	$	2		$	(4	)
Net realized losses recognized during the period		(4	)		(7	)

Net Outstanding Commodity Forward Contracts That Did Not Qualify For Hedge Accounting

	March 31, 2013				December 31, 2012
Commodity	Quantity		Net Position		Quantity		Net Position
Natural gas (one Million British Thermal Units (MMBtu))		3,245,000		Long		3,838,000		Long

XML

Pension And Other Postretirement Benefits (Components Of Net Periodic Benefit Cost) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 13	$ 11
Interest cost	25	26
Expected return on plan assets	(37)	(34)
Amortization of net actuarial loss	16	14
Net periodic benefit cost	17	17
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	2	1
Interest cost	8	9
Expected return on plan assets	(5)	(5)
Amortization of prior service cost	(1)	(1)
Amortization of net actuarial loss	4	5
Net periodic benefit cost	$ 8	$ 9

XML

Derivative Instruments And Hedging Activities

3 Months Ended

Mar. 31, 2013

Derivative Instruments And Hedging Activities

(13) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

The retail electric 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 futures, swaps, options and forward contracts to hedge commodity price risk in connection with the purchase of physical 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 Power Delivery, 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 uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. 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.

ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would receive payments from or make payments to electric generation facilities based on i) the difference between the fixed price in the SOCAs and the price for capacity that clears PJM and ii) ACE’s annual proportion of the total New Jersey load relative to the other EDCs in New Jersey, which is currently estimated to be approximately 15 percent. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because the generators cleared the 2015-2016 PJM capacity auction in May 2012. Changes in the fair value of the derivatives embedded in the SOCAs are deferred as Regulatory Assets or Regulatory Liabilities because the NJBPU has allowed full recovery from ACE’s distribution customers for all payments made by ACE, and ACE’s distribution customers would be entitled to all payments received by ACE.

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 its 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 Accumulated Other Comprehensive Loss (AOCL) and is being recognized in income over the life of the debt issued as interest payments are made.

The tables below identify the balance sheet location and fair values of derivative instruments as of March 31, 2013 and December 31, 2012:

	As of March 31, 2013
Balance Sheet Caption	Derivatives Designated as Hedging Instruments (a)			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments
	(millions of dollars)
Derivative assets (current assets)	$	—		$	1		$	1		$	(1	)	$	—
Derivative assets (non-current assets)		—			8			8			—			8
Total Derivative assets		—			9			9			(1	)		8
Derivative liabilities (current liabilities)		(2	)		(2	)		(4	)		2			(2	)
Derivative liabilities (non-current liabilities)		—			(11	)		(11	)		—			(11	)
Total Derivative liabilities		(2	)		(13	)		(15	)		2			(13	)
Net Derivative (liability) asset	$	(2	)	$	(4	)	$	(6	)	$	1		$	(5	)

(a) Amounts included in Derivatives Designated as Hedging Instruments primarily consist of derivatives that were designated as cash flow hedges prior to Pepco Energy Services’ election to discontinue cash flow hedge accounting for these derivatives.

	As of December 31, 2012
Balance Sheet Caption	Derivatives Designated as Hedging Instruments (a)			Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	(millions of dollars)
Derivative assets (current assets)	$	—		$	1		$	1		$	—	$	1
Derivative assets (non-current assets)		—			8			8			—		8
Total Derivative assets		—			9			9			—		9
Derivative liabilities (current liabilities)		(5	)		(8	)		(13	)		6		(7	)
Derivative liabilities (non-current liabilities)		—			(11	)		(11	)		—		(11	)
Total Derivative liabilities		(5	)		(19	)		(24	)		6		(18	)
Net Derivative (liability) asset	$	(5	)	$	(10	)	$	(15	)	$	6	$	(9	)

(a) Amounts included in Derivatives Designated as Hedging Instruments primarily consist of derivatives that were designated as cash flow hedges prior to Pepco Energy Services’ election to discontinue cash flow hedge accounting for these derivatives.

Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), PHI offsets the fair value amounts recognized for derivative assets and liabilities and the fair value amounts recognized for related collateral positions executed with the same counterparty under master netting agreements. All derivative assets and liabilities available to be offset under master netting arrangements were netted as of March 31, 2013 and December 31, 2012. The amount of cash collateral that was offset against these derivative positions is as follows:

	March 31, 2013			December 31, 2012
	(millions of dollars)
Cash collateral pledged to counterparties with the right to reclaim (a)	$	2		$	6
Cash collateral received from counterparties with the obligation to return		(1	)		—

(a) Includes cash deposits on commodity brokerage accounts.

As of March 31, 2013 and December 31, 2012, all PHI 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

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. The retail electric business of Pepco Energy Services does not apply cash flow hedge accounting to certain of its electricity derivatives. Amounts included in AOCL for these cash flow hedges as of March 31, 2013 and 2012 represent net losses on derivatives prior to the election to discontinue cash flow hedge accounting less amounts reclassified into income as the hedged transactions occur or because the hedged transactions were deemed probable not to occur. Gains or losses on these derivatives after the election to discontinue cash flow hedge accounting are recognized in income.

The cash flow hedge activity during the three months ended March 31, 2013 and 2012 is provided in the tables below:

	Three Months Ended March 31,
	2013		2012
	(millions of dollars)
Amount of net pre-tax loss arising during the period included in Accumulated Other Comprehensive Loss	$	—	$	—
Amount of net pre-tax loss reclassified into income:
Effective portion:
Fuel and Purchased Energy expense		3		7
Ineffective portion: (a)
Revenue		—		—
Total net pre-tax loss reclassified into income		3		7
Net pre-tax gain on commodity derivatives included in Accumulated Other Comprehensive Loss	$	3	$	7

(a) For the three months ended March 31, 2013 and 2012, no amounts were reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur.

As of March 31, 2013 and December 31, 2012, the retail electric business of Pepco Energy Services had no outstanding energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.

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 sheets as of March 31, 2013 and 2012. Cash flow hedges are marked to market on the consolidated balance sheet with corresponding adjustments to AOCL for effective cash flow hedges. As of March 31, 2013 and 2012, $2 million and $16 million, respectively, of the losses in AOCL were associated with derivatives that the retail electric business of Pepco Energy Services previously designated as cash flow hedges. Although the retail electric business of Pepco Energy Services no longer designates these derivatives as cash flow hedges, gains or losses previously deferred in AOCL prior to the decision to discontinue cash flow hedge accounting will remain in AOCL until the hedged forecasted transaction occurs unless it is deemed probable that the hedged forecasted transaction will not occur. The data in the following 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:

Contracts	As of March 31, 2013				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Energy commodity (a)	$	1	$	1		2 months
Interest rate		10		1		233 months
Total	$	11	$	2

(a) The unrealized derivative losses recorded in AOCL relate to forecasted physical electricity purchases which are used to supply retail electricity contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on PHI’s consolidated balance sheet for the retail contracts and the purchase cost is not recognized until the period of distribution.

Contracts	As of March 31, 2012				Maximum Term
	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months
	(millions of dollars)
Energy commodity (a)	$	11	$	10		14 months
Interest rate		10		1		245 months
Total	$	21	$	11

(a) The unrealized derivative losses recorded in AOCL relate to forecasted physical and electricity purchases which are used to supply retail electricity contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on PHI’s consolidated balance sheet for the retail contracts and the purchase cost is not recognized until the period of distribution.

Other Derivative Activity

Pepco Energy Services

The retail electric business of Pepco Energy Services holds certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the balance sheet with the gain or loss for changes in fair value recorded through Fuel and Purchased Energy expense.

For the three months ended March 31, 2013 and 2012, the amount of the derivative gain (loss) for the retail electric business of Pepco Energy Services recognized in income is provided in the table below:

	Three Months Ended March  31,
	2013		2012
	(millions of dollars)
Reclassification of mark-to-market to realized on settlement of contracts	$	2	$	2
Unrealized mark-to-market loss		—		(4	)
Total net gain (loss)	$	2	$	(2	)

As of March 31, 2013 and December 31, 2012, the retail electric business of Pepco Energy Services had the following net outstanding commodity forward contract quantities and net position on derivatives that did not qualify for hedge accounting:

	March 31, 2013				December 31, 2012
Commodity	Quantity		Net Position		Quantity		Net Position
Financial transmission rights (MWh)		86,746		Long		181,008		Long
Electricity (MWh)		131,640		Long		261,240		Long

Power Delivery

DPL and ACE have certain derivatives that are not in hedge accounting relationships and are not 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 changes 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 DPL’s derivatives and the NJBPU order pertaining to the SOCAs within which ACE’s capacity derivatives are embedded. The following table indicates the net unrealized derivative gains and losses arising during the period that were deferred as Regulatory Liabilities and Regulatory Assets, respectively, and the net realized losses recognized in the consolidated statements of income (through Fuel and Purchased Energy expense) that were also deferred as Regulatory Assets for the three months ended March 31, 2013 and 2012 associated with these derivatives:

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
Net unrealized gain (loss) arising during the period	$	2		$	(4	)
Net realized loss recognized during the period		(4	)		(7	)

As of March 31, 2013 and December 31, 2012, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts and ACE’s capacity derivatives associated with the SOCAs that did not qualify for hedge accounting were:

	March 31, 2013				December 31, 2012
Commodity	Quantity		Net Position		Quantity		Net Position
DPL – Natural gas (one Million British Thermal Units (MMBtu))		3,245,000		Long		3,838,000		Long
ACE – Capacity (MWs)		180		Long		180		Long

Contingent Credit Risk Features

The primary contracts used by the retail electric business of Pepco Energy Services and the Power Delivery segment 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 the retail electric business 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 debt 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 values of PHI’s derivative liabilities with credit risk-related contingent features as of March 31, 2013 and December 31, 2012, were $2 million and $8 million, respectively, before giving effect to offsetting transactions or collateral under master netting agreements. As of March 31, 2013 and December 31, 2012, PHI had posted no cash collateral against its gross derivative liability, resulting in a net liability of $2 million and $8 million, respectively. If PHI’s and DPL’s debt ratings had been downgraded below investment grade as of March 31, 2013 and December 31, 2012, PHI’s net settlement amounts, including both the fair value of its derivative liabilities and its normal purchase and normal sale contracts would have been approximately $24 million and $40 million, respectively, and PHI would have been required to post collateral with the counterparties of approximately $24 million and $40 million, respectively, in addition to that which was posted as of March 31, 2013 and December 31, 2012. The net settlement and additional collateral amounts reflect the effect of offsetting transactions under master netting agreements.

PHI’s primary source for posting cash collateral or letters of credit is its credit facility. At March 31, 2013 and December 31, 2012, the aggregate amount of cash plus borrowing capacity under the credit facility available to meet the future liquidity needs of PHI and its subsidiaries totaled $975 million and $861 million, respectively, of which $340 million and $384 million, respectively, was available to the retail electric business of Pepco Energy Services.

Delmarva Power & Light Co/De [Member]

Derivative Instruments And Hedging Activities

(11) 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 limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. 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 March 31, 2013 and December 31, 2012:

	As of March 31, 2013
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)	$	—	$	1	$	1	$	(1	)	$	—
Derivative assets (non-current assets)		—		—		—		—			—
Net Derivative asset	$	—	$	1	$	1	$	(1	)	$	—

	As of December 31, 2012
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)	$	—	$	(4	)	$	(4	)	$	—	$	(4	)
Derivative liabilities (non-current liabilities)		—		—			—			—		—
Net Derivative liability	$	—	$	(4	)	$	(4	)	$	—	$	(4	)

Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), 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. All derivative assets and liabilities available to be offset under master netting arrangements were netted as of March 31, 2013 and December 31, 2012. The amount of cash collateral that was offset against these derivative positions is as follows:

	March 31, 2013			December 31, 2012
	(millions of dollars)
Cash collateral received from counterparties with the obligation to return	$	(1	)	$	—

As of March 31, 2013 and December 31, 2012, all DPL cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.

Other Derivative Activity

DPL holds certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the balance sheets with the gain or loss for 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 derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause. For the three months ended March 31, 2013 and 2012, the net unrealized derivative gains and losses arising during the period that were deferred as Regulatory Liabilities and Regulatory Assets and the net realized losses recognized in the statements of income (through Purchased Energy and Gas Purchased expense) that were also deferred as Regulatory Assets are provided in the table below:

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
Net unrealized gains (losses) arising during the period	$	2		$	(4	)
Net realized losses recognized during the period		(4	)		(7	)

As of March 31, 2013 and December 31, 2012, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

	March 31, 2013				December 31, 2012
Commodity	Quantity		Net Position		Quantity		Net Position
Natural gas (one Million British Thermal Units (MMBtu))		3,245,000		Long		3,838,000		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 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 debt 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 values of DPL’s derivative liabilities with credit-risk-related contingent features as of March 31, 2013 and December 31, 2012, was zero and $4 million, respectively. As of those dates, DPL had posted no cash collateral in the normal course of business against its gross derivative liabilities, resulting in net liabilities of zero and $4 million, respectively. If DPL’s debt ratings had been downgraded below investment grade as of March 31, 2013 and December 31, 2012, DPL’s net settlement amounts would have been approximately zero and $2 million, respectively, and DPL would have been required to post collateral with the counterparties of approximately zero and $2 million, respectively. The net settlement and additional collateral amounts reflect the effect of offsetting transactions under master netting agreements.

DPL’s primary source for posting cash collateral or letters of credit is PHI’s credit facility. At March 31, 2013 and December 31, 2012, the aggregate amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries was $635 million and $477 million, respectively.

Atlantic City Electric Co [Member]

Derivative Instruments And Hedging Activities

(10) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would receive payments from or make payments to electric generation facilities based on (i) the difference between the fixed price in the SOCAs and the price for capacity that clears PJM and (ii) ACE’s annual proportion of the total New Jersey load relative to the other EDCs in New Jersey, which is currently estimated to be 15 percent. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because the generators cleared the 2015-2016 PJM capacity auction in May 2012. Changes in the fair value of the derivatives embedded in the SOCAs are deferred as Regulatory Assets or Regulatory Liabilities because the NJBPU has allowed full recovery from ACE’s distribution customers for all payments made by ACE, and ACE’s distribution customers would be entitled to all payments received by ACE.

As of March 31, 2013, ACE had non-current Derivative Assets of $8 million and non-current Derivative Liabilities of $11 million associated with the two SOCAs and an offsetting regulatory liability and regulatory asset, respectively, of the same amounts. As of March 31, 2013, ACE had 180 MWs of capacity in a long position, with no collateral or netting applicable to the capacity. Unrealized gains and losses associated with these capacity derivatives, which netted to an unrealized loss of zero for the three months ended March 31, 2013, have been deferred as Regulatory Liabilities and Regulatory Assets.

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Related Party Transactions

3 Months Ended

Mar. 31, 2013

Potomac Electric Power Co [Member]

Related Party Transactions

(12) 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 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 March 31, 2013 and 2012 were approximately $55 million and $51 million, respectively.

Pepco Energy Services performs utility maintenance services and high voltage underground transmission cabling, including services that are treated as capital costs, for Pepco. Amounts charged to Pepco by Pepco Energy Services for the three months ended March 31, 2013 and 2012 were approximately $8 million and $5 million, respectively.

As of March 31, 2013 and December 31, 2012, Pepco had the following balances on its balance sheets due to related parties:

	March 31, 2013			December 31, 2012
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(31	)	$	(22	)
Pepco Energy Services (b)		(17	)		(18	)
Other		(1	)		(1	)
Total	$	(49	)	$	(41	)

(a) Included in Accounts Payable Due to Associated Companies.

(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. Amount also includes charges for utility work performed by Pepco Energy Services on behalf of Pepco.

Delmarva Power & Light Co/De [Member]

Related Party Transactions

(14) 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 methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to DPL for the three months ended March 31, 2013 and 2012 were approximately $40 million and $37 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:

	Three Months Ended March  31,
	2013		2012
	(millions of dollars)
Intercompany lease transactions (a)	$	1	$	1

(a) Included in Electric revenue.

As of March 31, 2013 and December 31, 2012, DPL had the following balances on its balance sheets due to related parties:

	March 31, 2013			December 31, 2012
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(21	)	$	(19	)
Other		(1	)		(1	)
Total	$	(22	)	$	(20	)

(a) Included in Accounts Payable Due to Associated Companies.

Atlantic City Electric Co [Member]

Related Party Transactions

(13) 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 methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to ACE for the three months ended March 31, 2013 and 2012 were approximately $31 million and $28 million, respectively.

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

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
Meter reading services provided by Millennium Account Services LLC (an ACE affiliate) (a)	$	(1	)	$	(1	)

(a) Included in Other Operation and Maintenance expense.

As of March 31, 2013 and December 31, 2012, ACE had the following balances on its consolidated balance sheets due to related parties:

	March 31, 2013			December 31, 2012
	(millions of dollars)
Payable to Related Party (current) (a)
PHI Service Company	$	(16	)	$	(13	)
Other		(1	)		(1	)
Total	$	(17	)	$	(14	)

(a) Included in Accounts Payable Due to Associated Companies.

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Leasing Activities (Income Recognized From Cross-Border Energy Lease Investments) (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Leases [Abstract]
Interest expense on uncertain tax positions	$ 16

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Significant Accounting Policies (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended
	Oct. 31, 2011 Y MW	Mar. 31, 2013 MW	Mar. 31, 2012	Jun. 30, 2012 MW
Significant Accounting Policies [Line Items]
Purchase of energy		$ 600	$ 641
Taxes included in gross revenues		84	86
Atlantic City Electric Co [Member]
Significant Accounting Policies [Line Items]
Number of purchase power agreements		3
Term of agreement, years		15
Equity ownership percentage		100.00%
Number of Standard Offer Capacity Agreements		3
Estimated share of payments received or made to generation companies		15.00%
Taxes included in gross revenues		3	4
Atlantic City Electric Co [Member] | Non-Utility Generators [Member]
Significant Accounting Policies [Line Items]
Megawatts received from power purchase agreements (PPAs)		459
Net power purchases with non-utility generators		54	51
Purchase of energy		54	50
Delmarva Power & Light Co/De [Member]
Significant Accounting Policies [Line Items]
Taxes included in gross revenues		4	4
Delmarva Power & Light Co/De [Member] | Fuel Cell Facility [Member]
Significant Accounting Policies [Line Items]
Term of agreement, years	21
Power of fuel cell facility, MW	30	27		3
Increments to power of fuel cell facility, MW		5
Amount billed to distribution customers		3	0
Delmarva Power & Light Co/De [Member] | Wind PPA [Member]
Significant Accounting Policies [Line Items]
Megawatts received from power purchase agreements (PPAs)		128
Purchase of energy		10	9
Delmarva Power & Light Co/De [Member] | Wind PPA [Member] | Wind Facility One [Member]
Significant Accounting Policies [Line Items]
Energy purchase maximum to be purchased, MW		50
Delmarva Power & Light Co/De [Member] | Wind PPA [Member] | Wind Facility Two [Member]
Significant Accounting Policies [Line Items]
Energy purchase maximum to be purchased, MW		40
Delmarva Power & Light Co/De [Member] | Wind PPA [Member] | Wind Facility Three [Member]
Significant Accounting Policies [Line Items]
Energy purchase maximum to be purchased, MW		38
Delmarva Power & Light Co/De [Member] | Solar PPA [Member]
Significant Accounting Policies [Line Items]
Number of purchase power agreements		1
Megawatts received from power purchase agreements (PPAs)		10
Term of agreement, years		20
Obligated purchase amount of energy produced at the facility		70.00%
Delmarva Power & Light Co/De [Member] | Solar PPA [Member] | Maximum [Member]
Significant Accounting Policies [Line Items]
Solar energy purchases		1	0
Delmarva Power & Light Co/De [Member] | Land-Based Wind PPA [Member]
Significant Accounting Policies [Line Items]
Number of purchase power agreements		3
Potomac Electric Power Co [Member]
Significant Accounting Policies [Line Items]
Taxes included in gross revenues		$ 77	$ 78

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Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Accounts receivable, allowance for uncollectible accounts	$ 39	$ 36
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	400,000,000	400,000,000
Common stock, shares outstanding	248,551,381	230,015,427
Potomac Electric Power Co [Member]
Accounts receivable, allowance for uncollectible accounts	12	13
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares outstanding	100	100
Delmarva Power & Light Co/De [Member]
Accounts receivable, allowance for uncollectible accounts	14	9
Common stock, par value	$ 2.25	$ 2.25
Common stock, shares authorized	1,000	1,000
Common stock, shares outstanding	1,000	1,000
Atlantic City Electric Co [Member]
Accounts receivable, allowance for uncollectible accounts	$ 10	$ 11
Common stock, par value	$ 3.00	$ 3.00
Common stock, shares authorized	25,000,000	25,000,000
Common stock, shares outstanding	8,546,017	8,546,017

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Related Party Transactions (Schedule Of Related Party Transactions Included In Income Statement) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Delmarva Power & Light Co/De [Member]
Related Party Transaction [Line Items]
Intercompany lease transactions	$ 1	[1]	$ 1	[1]
Atlantic City Electric Co [Member] | Millennium Account Services LLC (ACE Affiliate) [Member]
Related Party Transaction [Line Items]
Amounts of transaction	$ (1)	[2]	$ (1)	[2]

[1] Included in Electric revenue.

[2] Included in Other Operation and Maintenance expense.

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Significant Accounting Policies

3 Months Ended

Mar. 31, 2013

Significant Accounting Policies

(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 consolidated financial statements prepared in accordance with GAAP have been omitted. Therefore, these consolidated financial statements should be read along with the annual consolidated financial statements included in PHI’s annual report on Form 10-K for the year ended December 31, 2012. 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 March 31, 2013, in accordance with GAAP. The year-end December 31, 2012 consolidated balance sheet included herein was derived from audited consolidated financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2013 may not be indicative of PHI’s results that will be realized for the full year ending December 31, 2013.

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 contingencies, future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefit assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto liability claims, accrual of interest related to income taxes, 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 (see Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust”), and income tax provisions and reserves. 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.

Consolidation of Variable Interest Entities

PHI assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. Subsidiaries of PHI have the following contractual arrangements 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) totaling 459 megawatts (MWs). One of the agreements ends in 2016 and the other two end in 2024. PHI was unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, PHI 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 March 31, 2013 and 2012 were approximately $54 million and $51 million, respectively, of which approximately $54 million and $50 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. As of March 31, 2013, PHI, through its DPL subsidiary, is a party to three land-based wind PPAs in the aggregate amount of 128 MWs and one solar PPA with a 10 MW facility. Each of the facilities associated with these PPAs is operational, and DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and solar renewable energy credits (SRECs) from the solar facility up to certain amounts (as set forth below) at rates that are primarily fixed under the PPAs. PHI has concluded that consolidation is not required for any of these PPAs under the FASB guidance on the consolidation of variable interest entities.

DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs, in each case at the rates primarily fixed by the PPA. DPL’s purchases under the three wind PPAs totaled $10 million and $9 million for the three months ended March 31, 2013 and 2012, respectively.

The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. DPL’s purchases under the solar agreement were less than one million and zero for the three months ended March 31, 2013 and 2012, respectively.

On October 18, 2011, the Delaware Public Service Commission (DPSC) approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. 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 MW hour (MWh) of energy produced by the fuel cell facilities over 21 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 provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. In June 2012, a 3 MW fuel cell generation facility was placed into service under the tariff. DPL billed $3 million and zero to distribution customers for the three months ended March 31, 2013 and 2012, respectively. A 27 MW fuel cell generation facility is expected to be placed into service over time, with the first 5 MW increment having been placed into service at the end of 2012. DPL has concluded that consolidation under the variable interest entity consolidation guidance is not required for this arrangement.

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 consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

ACE Standard Offer Capacity Agreements

In April 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 generation companies to receive payments from, or require them to 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 electric distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. ACE’s share of the payments received from or the payments made to the generation companies is currently estimated to be approximately 15 percent, based on its proportionate share of the total New Jersey electric load for all EDCs. The NJBPU has ordered that ACE is obligated to distribute to its distribution customers all payments it receives from the generation companies and may recover from its distribution customers all payments it makes to the generation companies. For additional discussion about the SOCAs, see Note (7), “Regulatory Matters.”

In May 2012, all three generation companies under the SOCAs bid into the PJM 2015-2016 capacity auction and two of the generators cleared that capacity auction. ACE recorded a derivative asset (liability) for the estimated fair value of each SOCA and recorded an offsetting regulatory liability (asset) as described in more detail in Note (13), “Derivative Instruments and Hedging Activities,” and Note (14), “Fair Value Disclosures.” FASB guidance on derivative accounting and the accounting for regulated operations would apply to ACE’s obligations under the third SOCA once the related capacity has cleared a PJM auction. The next PJM capacity auction is scheduled for May 2013. PHI has concluded that consolidation of the generation companies is not required.

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 (now Conectiv, LLC (Conectiv)) in 2002 and is allocated entirely to Power Delivery for purposes of impairment testing based on the aggregation of its components because its utilities have similar characteristics. 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 the carrying amount of its net assets. 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 protracted decline in PHI’s stock price causing market capitalization to fall 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 March 31, 2013.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $84 million and $86 million for the three months ended March 31, 2013 and 2012, respectively.

Reclassifications

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

Potomac Electric Power Co [Member]

Significant Accounting Policies

(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, 2012. 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 March 31, 2013, in accordance with GAAP. The year-end December 31, 2012 balance sheet included herein was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2013 may not be indicative of results that will be realized for the full year ending December 31, 2013.

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, future cash flows and fair value amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, 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.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $77 million and $78 million for the three months ended March 31, 2013 and 2012, respectively.

Reclassifications

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

Delmarva Power & Light Co/De [Member]

Significant Accounting Policies

(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, 2012. 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 March 31, 2013, in accordance with GAAP. The year-end December 31, 2012 balance sheet included herein was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2013 may not be indicative of DPL’s results that will be realized for the full year ending December 31, 2013.

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, 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, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, 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.

Consolidation of Variable Interest Entities—DPL Renewable Energy Transactions

DPL assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with ASC 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests.

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. As of March 31, 2013, PHI, through its DPL subsidiary, is a party to three land-based wind PPAs in the aggregate amount of 128 megawatts (MWs) and one solar PPA with a 10 MW facility. Each of the facilities associated with these PPAs is operational, and DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and solar renewable energy credits (SRECs) from the solar facility up to certain amounts (as set forth below) at rates that are primarily fixed under the PPAs. PHI has concluded that consolidation is not required for any of these PPAs under the Financial Accounting Standards Board (FASB) guidance on the consolidation of variable interest entities.

DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs, in each case at the rates primarily fixed by the PPA. DPL’s purchases under the three wind PPAs totaled $10 million and $9 million for the three months ended March 31, 2013 and 2012, respectively.

The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. DPL’s purchases under the solar agreement were less than one million and zero for the three months ended March 31, 2013 and 2012, respectively.

On October 18, 2011, the Delaware Public Service Commission (DPSC) approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. 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 MW hour (MWh) of energy produced by the fuel cell facilities over 21 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 provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. In June 2012, a 3 MW fuel cell generation facility was placed into service under the tariff. DPL billed $3 million and zero to distribution customers for the three months ended March 31, 2013 and 2012, respectively. A 27 MW fuel cell generation facility is expected to be placed into service over time, with the first 5 MW increment having been placed into service at the end of 2012. DPL has concluded that consolidation under the variable interest entity consolidation guidance is not required for this arrangement.

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 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 DPL below the carrying amount of its net assets. 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 March 31, 2013.

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 March 31, 2013 and 2012.

Atlantic City Electric Co [Member]

Significant Accounting Policies

(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 consolidated financial statements prepared in accordance with GAAP have been omitted. Therefore, these consolidated financial statements should be read along with the annual consolidated financial statements included in ACE’s annual report on Form 10-K for the year ended December 31, 2012. 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 March 31, 2013, in accordance with GAAP. The year-end December 31, 2012 consolidated balance sheet included herein was derived from audited consolidated financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2013 may not be indicative of ACE’s results that will be realized for the full year ending December 31, 2013.

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, future cash flows and fair value amounts for use in asset impairment evaluations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, 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.

Consolidation of Variable Interest Entities

ACE assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests.

ACE Power Purchase Agreements

ACE is a party to three power purchase agreements (PPAs) with unaffiliated, non-utility generators (NUGs) totaling 459 megawatts (MWs). One of the agreements ends in 2016 and the other two end in 2024. PHI was unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, ACE 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 March 31, 2013 and 2012 were approximately $54 million and $51 million, respectively, of which approximately $54 million and $50 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 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 consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

ACE Standard Offer Capacity Agreements

In April 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 generation companies to receive payments from, or require them to 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 electric distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. ACE’s share of the payments received from or the payments made to the generation companies is currently estimated to be approximately 15 percent, based on its proportionate share of the total New Jersey electric load for all EDCs. The NJBPU has ordered that ACE is obligated to distribute to its distribution customers all payments it receives from the generation companies and may recover from its distribution customers all payments it makes to the generation companies. For additional discussion about the SOCAs, see Note (6), “Regulatory Matters.”

In May 2012, all three generation companies under the SOCAs bid into the PJM 2015-2016 capacity auction and two of the generators cleared that capacity auction. ACE recorded a derivative asset (liability) for the estimated fair value of each SOCA and recorded an offsetting regulatory liability (asset) as described in more detail in Note (10), “Derivative Instruments and Hedging Activities,” and Note (11), “Fair Value Disclosures.” FASB guidance on derivative accounting and the accounting for regulated operations would apply to ACE’s obligations under the third SOCA once the related capacity has cleared a PJM auction. The next PJM capacity auction is scheduled for May 2013. PHI has concluded that consolidation of the generation companies is not required.

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were $3 million and $4 million for the three months ended March 31, 2013 and 2012, respectively.

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Derivative Instruments And Hedging Activities (Fair Value Of Derivative Instruments By Balance Sheet Location) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Derivative [Line Items]
Derivative assets (current assets)			$ 1
Derivative assets (non-current assets)	8		8
Total Derivative assets	200		113
Derivative liabilities (current liabilities)	(2)		(7)
Derivative liabilities (non-current liabilities)	(11)		(11)
Delmarva Power & Light Co/De [Member]
Derivative [Line Items]
Total Derivative assets	4		3
Derivative liabilities (current liabilities)			(4)
Derivatives Designated As Hedging Instruments [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	(2)	[1]	(5)	[1]
Total Derivative liabilities	(2)	[1]	(5)	[1]
Net Derivative (liability) asset	(2)	[1]	(5)	[1]
Other Derivative Instruments [Member]
Derivative [Line Items]
Derivative assets (current assets)	1		1
Derivative assets (non-current assets)	8		8
Total Derivative assets	9		9
Derivative liabilities (current liabilities)	(2)		(8)
Derivative liabilities (non-current liabilities)	(11)		(11)
Total Derivative liabilities	(13)		(19)
Net Derivative (liability) asset	(4)		(10)
Other Derivative Instruments [Member] | Delmarva Power & Light Co/De [Member]
Derivative [Line Items]
Derivative assets (current assets)	1
Total Derivative assets	1
Derivative liabilities (current liabilities)			(4)
Total Derivative liabilities			(4)
Gross Derivative Instruments [Member]
Derivative [Line Items]
Derivative assets (current assets)	1		1
Derivative assets (non-current assets)	8		8
Total Derivative assets	9		9
Derivative liabilities (current liabilities)	(4)		(13)
Derivative liabilities (non-current liabilities)	(11)		(11)
Total Derivative liabilities	(15)		(24)
Net Derivative (liability) asset	(6)		(15)
Gross Derivative Instruments [Member] | Delmarva Power & Light Co/De [Member]
Derivative [Line Items]
Derivative assets (current assets)	1
Total Derivative assets	1
Derivative liabilities (current liabilities)			(4)
Total Derivative liabilities			(4)
Effects Of Cash Collateral And Netting [Member]
Derivative [Line Items]
Derivative assets (current assets)	(1)
Total Derivative assets	(1)
Derivative liabilities (current liabilities)	2		6
Total Derivative liabilities	2		6
Net Derivative (liability) asset	1		6
Effects Of Cash Collateral And Netting [Member] | Delmarva Power & Light Co/De [Member]
Derivative [Line Items]
Derivative assets (current assets)	(1)
Total Derivative assets	(1)
Net Derivative Instruments [Member]
Derivative [Line Items]
Derivative assets (current assets)			1
Derivative assets (non-current assets)	8		8
Total Derivative assets	8		9
Derivative liabilities (current liabilities)	(2)		(7)
Derivative liabilities (non-current liabilities)	(11)		(11)
Total Derivative liabilities	(13)		(18)
Net Derivative (liability) asset	(5)		(9)
Net Derivative Instruments [Member] | Delmarva Power & Light Co/De [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)			(4)
Total Derivative liabilities			$ (4)

[1] Amounts included in Derivatives Designated as Hedging Instruments primarily consist of derivatives that were designated as cash flow hedges prior to Pepco Energy Services' election to discontinue cash flow hedge accounting for these derivatives.

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Discontinued Operations (Activity Of Energy Commodity Contracts Designated As Cash Flow Hedges) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Derivatives And Hedging Activities [Line Items]
Amount of net pre-tax loss arising during the period included in Accumulated Other Comprehensive Loss	$ 3		$ 7
Income from Discontinued Operations, Net of Income Taxes, Effective portion	3		7
Income from Discontinued Operations, Net of Income Taxes, Ineffective portion		[1]		[1]
Total net pre-tax loss reclassified into Income from Discontinued Operations, Net of Income Taxes	3		7
Net pre-tax gain on commodity derivatives included in Accumulated Other Comprehensive Loss	3		7
Amount reclassified from AOCL to income from discontinued operations	0		0
Discontinued Operations [Member]
Derivatives And Hedging Activities [Line Items]
Amount of net pre-tax loss arising during the period included in Accumulated Other Comprehensive Loss
Income from Discontinued Operations, Net of Income Taxes, Effective portion	1		6
Income from Discontinued Operations, Net of Income Taxes, Ineffective portion	4	[2]		[2]
Total net pre-tax loss reclassified into Income from Discontinued Operations, Net of Income Taxes	5		6
Net pre-tax gain on commodity derivatives included in Accumulated Other Comprehensive Loss	5		6
Amount reclassified from AOCL to income from discontinued operations	$ 4		$ 0

[1] For the three months ended March 31, 2013 and 2012, no amounts were reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur.

[2] Included in the table above is a loss of $4 million for the three months ended March 31, 2013, which was reclassified from AOCL to Income from Discontinued Operations, Net of Income Taxes because the forecasted hedged transactions were deemed probable not to occur. For the three months ended March 31, 2012, no amounts were reclassified from AOCL to Income from Discontinued Operations, Net of Income Taxes because the forecasted hedged transactions were deemed probable not to occur.

XML

Fair Value Disclosures (Reconciliations Of Fair Value Measurements Using Significant Unobservable Inputs (Level 3)) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Natural Gas [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	$ (4)	$ (15)
Included in accumulated other comprehensive loss
Included in regulatory assets (liabilities)		(3)
Purchases
Settlements	4	6
Transfers in (out) of level 3
Ending balance		(12)
Natural Gas [Member] | Delmarva Power & Light Co/De [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	(4)	(15)
Included in accumulated other comprehensive loss
Included in regulatory assets (liabilities)		(3)
Purchases
Settlements	4	6
Transfers in (out) of level 3
Ending balance		(12)
Life Insurance Contracts [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	18	17
Included in income	1	1
Included in accumulated other comprehensive loss
Purchases
Transfers in (out) of level 3
Ending balance	19	18
Life Insurance Contracts [Member] | Potomac Electric Power Co [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	18	17
Included in income	1	1
Included in accumulated other comprehensive loss
Purchases
Issuances	(1)
Transfers in (out) of level 3
Ending balance	18	18
Life Insurance Contracts [Member] | Delmarva Power & Light Co/De [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	1	1
Included in accumulated other comprehensive loss
Purchases
Transfers in (out) of level 3
Ending balance	1	1
Capacity [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	(3)
Included in accumulated other comprehensive loss
Purchases
Transfers in (out) of level 3
Ending balance	(3)
Capacity [Member] | Atlantic City Electric Co [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	(3)
Included in accumulated other comprehensive loss
Purchases
Transfers in (out) of level 3
Ending balance	$ (3)

XML

Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2013

Financial Statement Presentation

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 consolidated financial statements prepared in accordance with GAAP have been omitted. Therefore, these consolidated financial statements should be read along with the annual consolidated financial statements included in PHI’s annual report on Form 10-K for the year ended December 31, 2012. 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 March 31, 2013, in accordance with GAAP. The year-end December 31, 2012 consolidated balance sheet included herein was derived from audited consolidated financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2013 may not be indicative of PHI’s results that will be realized for the full year ending December 31, 2013.

Use Of Estimates

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 contingencies, future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefit assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto liability claims, accrual of interest related to income taxes, 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 (see Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust”), and income tax provisions and reserves. 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.

Consolidation Of Variable Interest Entities

Consolidation of Variable Interest Entities

PHI assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. Subsidiaries of PHI have the following contractual arrangements 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) totaling 459 megawatts (MWs). One of the agreements ends in 2016 and the other two end in 2024. PHI was unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, PHI 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 March 31, 2013 and 2012 were approximately $54 million and $51 million, respectively, of which approximately $54 million and $50 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. As of March 31, 2013, PHI, through its DPL subsidiary, is a party to three land-based wind PPAs in the aggregate amount of 128 MWs and one solar PPA with a 10 MW facility. Each of the facilities associated with these PPAs is operational, and DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and solar renewable energy credits (SRECs) from the solar facility up to certain amounts (as set forth below) at rates that are primarily fixed under the PPAs. PHI has concluded that consolidation is not required for any of these PPAs under the FASB guidance on the consolidation of variable interest entities.

DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs, in each case at the rates primarily fixed by the PPA. DPL’s purchases under the three wind PPAs totaled $10 million and $9 million for the three months ended March 31, 2013 and 2012, respectively.

The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. DPL’s purchases under the solar agreement were less than one million and zero for the three months ended March 31, 2013 and 2012, respectively.

On October 18, 2011, the Delaware Public Service Commission (DPSC) approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. 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 MW hour (MWh) of energy produced by the fuel cell facilities over 21 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 provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. In June 2012, a 3 MW fuel cell generation facility was placed into service under the tariff. DPL billed $3 million and zero to distribution customers for the three months ended March 31, 2013 and 2012, respectively. A 27 MW fuel cell generation facility is expected to be placed into service over time, with the first 5 MW increment having been placed into service at the end of 2012. DPL has concluded that consolidation under the variable interest entity consolidation guidance is not required for this arrangement.

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 consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

ACE Standard Offer Capacity Agreements

In April 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 generation companies to receive payments from, or require them to 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 electric distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. ACE’s share of the payments received from or the payments made to the generation companies is currently estimated to be approximately 15 percent, based on its proportionate share of the total New Jersey electric load for all EDCs. The NJBPU has ordered that ACE is obligated to distribute to its distribution customers all payments it receives from the generation companies and may recover from its distribution customers all payments it makes to the generation companies. For additional discussion about the SOCAs, see Note (7), “Regulatory Matters.”

In May 2012, all three generation companies under the SOCAs bid into the PJM 2015-2016 capacity auction and two of the generators cleared that capacity auction. ACE recorded a derivative asset (liability) for the estimated fair value of each SOCA and recorded an offsetting regulatory liability (asset) as described in more detail in Note (13), “Derivative Instruments and Hedging Activities,” and Note (14), “Fair Value Disclosures.” FASB guidance on derivative accounting and the accounting for regulated operations would apply to ACE’s obligations under the third SOCA once the related capacity has cleared a PJM auction. The next PJM capacity auction is scheduled for May 2013. PHI has concluded that consolidation of the generation companies is not required.

Goodwill

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 (now Conectiv, LLC (Conectiv)) in 2002 and is allocated entirely to Power Delivery for purposes of impairment testing based on the aggregation of its components because its utilities have similar characteristics. 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 the carrying amount of its net assets. 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 protracted decline in PHI’s stock price causing market capitalization to fall 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 March 31, 2013.

Taxes Assessed By A Governmental Authority On Revenue-Producing Transactions

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco Holdings’ gross revenues were $84 million and $86 million for the three months ended March 31, 2013 and 2012, respectively.

Reclassifications

Reclassifications

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

Potomac Electric Power Co [Member]

Financial Statement Presentation

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, 2012. 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 March 31, 2013, in accordance with GAAP. The year-end December 31, 2012 balance sheet included herein was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2013 may not be indicative of results that will be realized for the full year ending December 31, 2013.

Use Of Estimates

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, future cash flows and fair value amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, 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.

Taxes Assessed By A Governmental Authority On Revenue-Producing Transactions

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in Pepco’s gross revenues were $77 million and $78 million for the three months ended March 31, 2013 and 2012, respectively.

Reclassifications

Reclassifications

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

Delmarva Power & Light Co/De [Member]

Financial Statement Presentation

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, 2012. 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 March 31, 2013, in accordance with GAAP. The year-end December 31, 2012 balance sheet included herein was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2013 may not be indicative of DPL’s results that will be realized for the full year ending December 31, 2013.

Use Of Estimates

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, 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, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, 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.

Consolidation Of Variable Interest Entities

Consolidation of Variable Interest Entities—DPL Renewable Energy Transactions

DPL assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with ASC 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests.

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. As of March 31, 2013, PHI, through its DPL subsidiary, is a party to three land-based wind PPAs in the aggregate amount of 128 megawatts (MWs) and one solar PPA with a 10 MW facility. Each of the facilities associated with these PPAs is operational, and DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and solar renewable energy credits (SRECs) from the solar facility up to certain amounts (as set forth below) at rates that are primarily fixed under the PPAs. PHI has concluded that consolidation is not required for any of these PPAs under the Financial Accounting Standards Board (FASB) guidance on the consolidation of variable interest entities.

DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs, in each case at the rates primarily fixed by the PPA. DPL’s purchases under the three wind PPAs totaled $10 million and $9 million for the three months ended March 31, 2013 and 2012, respectively.

The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. DPL’s purchases under the solar agreement were less than one million and zero for the three months ended March 31, 2013 and 2012, respectively.

On October 18, 2011, the Delaware Public Service Commission (DPSC) approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. 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 MW hour (MWh) of energy produced by the fuel cell facilities over 21 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 provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. In June 2012, a 3 MW fuel cell generation facility was placed into service under the tariff. DPL billed $3 million and zero to distribution customers for the three months ended March 31, 2013 and 2012, respectively. A 27 MW fuel cell generation facility is expected to be placed into service over time, with the first 5 MW increment having been placed into service at the end of 2012. DPL has concluded that consolidation under the variable interest entity consolidation guidance is not required for this arrangement.

Goodwill

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 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 DPL below the carrying amount of its net assets. 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 March 31, 2013.

Taxes Assessed By A Governmental Authority On Revenue-Producing Transactions

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 March 31, 2013 and 2012.

Atlantic City Electric Co [Member]

Financial Statement Presentation

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 consolidated financial statements prepared in accordance with GAAP have been omitted. Therefore, these consolidated financial statements should be read along with the annual consolidated financial statements included in ACE’s annual report on Form 10-K for the year ended December 31, 2012. 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 March 31, 2013, in accordance with GAAP. The year-end December 31, 2012 consolidated balance sheet included herein was derived from audited consolidated financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2013 may not be indicative of ACE’s results that will be realized for the full year ending December 31, 2013.

Use Of Estimates

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, future cash flows and fair value amounts for use in asset impairment evaluations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, 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.

Consolidation Of Variable Interest Entities

Consolidation of Variable Interest Entities

ACE assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests.

ACE Power Purchase Agreements

ACE is a party to three power purchase agreements (PPAs) with unaffiliated, non-utility generators (NUGs) totaling 459 megawatts (MWs). One of the agreements ends in 2016 and the other two end in 2024. PHI was unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, ACE 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 March 31, 2013 and 2012 were approximately $54 million and $51 million, respectively, of which approximately $54 million and $50 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 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 consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

ACE Standard Offer Capacity Agreements

In April 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 generation companies to receive payments from, or require them to 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 electric distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. ACE’s share of the payments received from or the payments made to the generation companies is currently estimated to be approximately 15 percent, based on its proportionate share of the total New Jersey electric load for all EDCs. The NJBPU has ordered that ACE is obligated to distribute to its distribution customers all payments it receives from the generation companies and may recover from its distribution customers all payments it makes to the generation companies. For additional discussion about the SOCAs, see Note (6), “Regulatory Matters.”

In May 2012, all three generation companies under the SOCAs bid into the PJM 2015-2016 capacity auction and two of the generators cleared that capacity auction. ACE recorded a derivative asset (liability) for the estimated fair value of each SOCA and recorded an offsetting regulatory liability (asset) as described in more detail in Note (10), “Derivative Instruments and Hedging Activities,” and Note (11), “Fair Value Disclosures.” FASB guidance on derivative accounting and the accounting for regulated operations would apply to ACE’s obligations under the third SOCA once the related capacity has cleared a PJM auction. The next PJM capacity auction is scheduled for May 2013. PHI has concluded that consolidation of the generation companies is not required.

Taxes Assessed By A Governmental Authority On Revenue-Producing Transactions

Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions

Taxes included in ACE’s gross revenues were $3 million and $4 million for the three months ended March 31, 2013 and 2012, respectively.

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Commitments And Contingencies (Environmental Matters) (Detail) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended		1 Months Ended			1 Months Ended		3 Months Ended
	Jan. 31, 2011 gal	Mar. 31, 2013	Dec. 31, 2012	Jun. 30, 2012 PHI [Member]	Mar. 31, 2013 PHI [Member]	Dec. 31, 2012 PHI [Member]	Jun. 30, 2012 Potomac Electric Power Co [Member]	Jan. 31, 2011 Potomac Electric Power Co [Member] gal	Mar. 31, 2013 Potomac Electric Power Co [Member]	Mar. 31, 2013 Atlantic City Electric Co [Member]
Commitments And Contingencies [Line Items]
EPA costs to date to clean up site		$ 6								$ 6
Estimated costs remaining to remediate the site		6								6
Quantity of mineral oil spill (gallons)	4,500							4,500
Civil penalty and Supplement Environmental Projects cost				1			1
Investment in finance leases held in trust		869	1,237		869	1,237
Tax payment made	74
Income tax penalties	1
Interest expense assessed relating to disallowed deductions	28
Non-cash charge (after-tax)		377							377	377
Maximum tax penalty percentage		20.00%
Federal income tax benefits		192
Percentage of disallowed tax benefits associated with leases		100.00%
Potential interest on potential tax liability related to disallowed tax benefits		50
Deposit of additional taxes and related interest		$ 242

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Discontinued Operations (Tables) (Discontinued Operations [Member])

3 Months Ended

Mar. 31, 2013

Discontinued Operations [Member]

Operating Results For Retail Natural Gas Supply Business

	Three Months Ended March  31,
	2013			2012
	(millions of dollars)
Income from operations of discontinued operations, net of income taxes	$	2		$	5
Unrealized losses associated with retail natural gas supply contracts, net of income taxes		(2	)		—
Income From Discontinued Operations, Net of Income Taxes	$	—		$	5

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Equity And Earnings Per Share

3 Months Ended

Mar. 31, 2013

Text Block [Abstract]

Equity And Earnings Per Share

(12) EQUITY AND EARNINGS PER SHARE

Basic and Diluted Earnings Per Share

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

	Three Months Ended March 31,
	2013			2012
	(millions of dollars, except per share data)
Income (Numerator):
Net (Loss) Income from continuing operations	$	(430	)	$	63
Net (Loss) Income from discontinued operations		—			5
Net (Loss) Income	$	(430	)	$	68
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		237			228
Adjustment to shares outstanding		—			—
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		237			228
Net effect of potentially dilutive shares (a)		—			—
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		237			228
Basic and Diluted Earnings per Share
(Loss) Earnings per share of common stock from continuing operations	$	(1.82	)	$	0.28
Earnings per share of common stock from discontinued operations		—			0.02
Basic and diluted (loss) earnings per share	$	(1.82	)	$	0.30

(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted EPS as they are considered to be anti-dilutive were zero and 3,000 for the three months ended March 31, 2013 and 2012, respectively.

Equity Forward Transaction

During 2012, PHI entered into an equity forward transaction in connection with a public offering of PHI common stock. Pursuant to the terms of this transaction, a forward counterparty borrowed 17,922,077 shares of PHI’s common stock from third parties and sold them to a group of underwriters for $19.25 per share, less an underwriting discount equal to $0.67375 per share. Under the terms of the equity forward transaction, upon physical settlement thereof, PHI was required to issue and deliver the shares of PHI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $18.57625 per share at the time the equity forward transaction was entered into and was subject to reduction from time to time in accordance with the terms of the equity forward transaction. On February 27, 2013, PHI physically settled the equity forward at the then applicable forward sale price of $17.39. The proceeds of approximately $312 million were used to repay outstanding commercial paper, a portion of which had been issued in order to make capital contributions to the utilities, and for general corporate purposes.

Treasury Stock

Premium on stock and other capital contributions on PHI’s consolidated balance sheet at March 31, 2013 includes approximately $2 million of treasury stock outstanding, representing 102,933 shares with a weighted-average price of $19.93. These shares were repurchased during the first quarter of 2013 to cover minimum withholding taxes of certain participants in PHI’s Long-Term Incentive Plan.